UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-K
 
[X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 20122015
OR
[   ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period from _________ to ___________

Commission File
Number
Registrant; State of Incorporation;
Address and Telephone Number
IRS Employer
Identification No.
   
1-114591-37388
PPLTalen Energy Corporation
(Exact name of Registrant as specified in its charter)
(Pennsylvania)Delaware
Two North Ninth(State or other jurisdiction of incorporation or organization)
835 Hamilton Street Suite 150
Allentown, PA  18101-1179
(610) 774-5151(888) 211-6011
23-2758192
47-1197305
1-32944
PPLTalen Energy Supply, LLC
(Exact name of Registrant as specified in its charter)
(Delaware)Delaware
Two North Ninth(State or other jurisdiction of incorporation or organization)
835 Hamilton Street Suite 150
Allentown, PA  18101-1179
(610) 774-5151(888) 211-6011
23-3074920
1-905
PPL Electric Utilities Corporation
(Exact name of Registrant as specified in its charter)
(Pennsylvania)
Two North Ninth Street
Allentown, PA  18101-1179
(610) 774-5151
23-0959590
333-173665
LG&E and KU Energy LLC
(Exact name of Registrant as specified in its charter)
(Kentucky)
220 West Main Street
Louisville, Kentucky 40202-1377
(502) 627-2000
20-0523163
1-2893
Louisville Gas and Electric Company
(Exact name of Registrant as specified in its charter)
(Kentucky)
220 West Main Street
Louisville, Kentucky 40202-1377
(502) 627-2000
61-0264150
1-3464
Kentucky Utilities Company
(Exact name of Registrant as specified in its charter)
(Kentucky and Virginia)
One Quality Street
Lexington, Kentucky 40507-1462
(502) 627-2000
61-0247570

Securities registered pursuant to Section 12(b) of the Act:


Securities registered pursuant to Section 12(b) of the Act:
Title of each className of each exchange on which registered
 
Common Stock of PPL CorporationNew York Stock Exchange
 
Corporate Units issued 2011 of PPL CorporationNew York Stock Exchange
Corporate Units issued 2010 of PPL CorporationNew York Stock Exchange
Junior Subordinated Notes of PPL Capital Funding, Inc.
2007 Series A due 2067New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
 
Common Stock of PPL Electric UtilitiesTalen Energy Corporation New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whetherif the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

PPL
Talen Energy Corporation
Yes  X   
No   X  
PPLTalen Energy Supply, LLC
Yes
No   X
PPL Electric Utilities Corporation
Yes        
No  X   
LG&E and KU Energy LLC
Yes        
No  X   
Louisville Gas and Electric Company
Yes        
No  X   
Kentucky Utilities Company
Yes        
No  X   

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

PPL
Talen Energy Corporation
Yes
No   X  
PPLTalen Energy Supply, LLC
Yes
No   X
PPL Electric Utilities Corporation
Yes  
No  X   
LG&E and KU Energy LLC
Yes        
No  X   
Louisville Gas and Electric Company
Yes        
No  X   
Kentucky Utilities Company
Yes        
No  X   

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

PPL
Talen Energy Corporation
Yes   X  
No
PPLTalen Energy Supply, LLC
Yes  X   
No
PPL Electric Utilities Corporation
Yes   X  
No        
LG&E and KU Energy LLC
Yes  X   
No        
Louisville Gas and Electric Company
Yes  X   
No        
Kentucky Utilities Company
Yes  X   
No        




(Note: Talen Energy Supply has filed all reports required under section 13 or 15(d) of the Exchange Act during the preceding 12 months, but since January 1, 2016, has not been subject to the filing requirements of Section 13 or 15(d) of the Exchange Act.)

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site,sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).

PPL
Talen Energy Corporation
Yes   X  
No
PPLTalen Energy Supply, LLC
Yes   X  
No
PPL Electric Utilities Corporation
Yes   X  
No        
LG&E and KU Energy LLC
Yes   X  
No        
Louisville Gas and Electric Company
Yes   X  
No        
Kentucky Utilities Company
Yes   X  
No        

Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrants'each of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

PPL
Talen Energy Corporation[ X ]
PPLTalen Energy Supply, LLC[ X ]
PPL Electric Utilities Corporation[ X ]
LG&E and KU Energy LLC[ X ]
Louisville Gas and Electric Company[ X ]
Kentucky Utilities Company[ X ]


Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or a smaller reporting company.companies. See definitionthe definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.  (Check one):

 
Large accelerated
filer
Accelerated
filer
Non-accelerated
filer
Smaller reporting
company
PPL Corporation[ X ][     ][     ][     ]
PPLTalen Energy Supply, LLC[     ][     ][ X ][     ]
PPL Electric Utilities Corporation[     ][     ][ X ][     ]
LG&E and KUTalen Energy Supply, LLC[     ][     ][ X ][     ]
Louisville Gas and Electric Company[     ][     ][ X ][     ]
Kentucky Utilities Company[     ][     ][ X ][     ]

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

PPL
Talen Energy Corporation
Yes
No   X  
PPLTalen Energy Supply, LLC
Yes
No   X  
PPL Electric Utilities Corporation
Yes        
No  X   
LG&E and KU Energy LLC
Yes        
No  X   
Louisville Gas and Electric Company
Yes        
No  X   
Kentucky Utilities Company
Yes        
No  X   

As of June 29, 2012, PPL30, 2015, Talen Energy Corporation had 580,212,689128,508,921 shares of its $.01$0.001 par value Common Stock outstanding. The aggregate market value of these common shares (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $16,135,714,881.$1,429,161,711. In determining this figure, the registrant has assumed that the executive officers of the registrant, the registrant's directors, and affiliates of Riverstone Holdings LLC are affiliates of the registrant. Such assumptions shall not be deemed to be conclusive for any other purpose. As of January 31, 2013, PPL29, 2016, Talen Energy Corporation had 582,846,910128,526,720 shares of its $.01$0.001 par value Common Stock outstanding.

As of January 31, 2013, PPL Corporation held all 66,368,056 outstanding common shares,There is no par value, of PPL Electric Utilities Corporation.

PPLestablished public trading market for Talen Energy Supply's membership interests, and Talen Energy Corporation indirectly holds all of the membership interests in PPLTalen Energy Supply, LLC.

PPL Corporation directly holds all of the membership interests in LG&E and KU Energy LLC.

As of January 31, 2013, LG&E and KU Energy LLC held all 21,294,223 outstanding common shares, no par value, of Louisville Gas and Electric Company.

As of January 31, 2013, LG&E and KU Energy LLC held all 37,817,878 outstanding common shares, no par value, of Kentucky Utilities Company.

PPLTalen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company meetmeets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K and areis therefore filing this form with the reduced disclosure format.

Documents incorporated by reference:

PPLTalen Energy Corporation has incorporated herein by reference certain sections of PPLTalen Energy Corporation's 2013 Notice ofproxy statement related to its 2016 Annual Meeting and Proxy Statement,of Stockholders, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 2012.2015. Such Statementsproxy statement will provide certain of the information required by Part III of this Report.


Table of Contents

PPLTALEN ENERGY CORPORATION
PPLTALEN ENERGY SUPPLY, LLC
PPL ELECTRIC UTILITIES CORPORATION
LG&E AND KU ENERGY LLC
LOUISVILLE GAS AND ELECTRIC COMPANY
KENTUCKY UTILITIES COMPANY

FORM 10-K ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 20122015

This combined Form 10-K is separately filed by the following registrants in their individual capacity: Talen Energy Corporation and Talen Energy Supply, LLC. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf, and neither registrant makes any representation as to information relating to the other registrant except that information relating to Talen Energy Supply, LLC and its subsidiaries is also attributed to Talen Energy Corporation and information relating to the subsidiaries of Talen Energy Supply, LLC is also attributed to Talen Energy Supply, LLC.

As Talen Energy Corporation is substantially comprised of Talen Energy Supply, LLC and its subsidiaries, to avoid repetition, most disclosures refer to Talen Energy which indicates the disclosure applies to each of the registrants, Talen Energy Corporation and Talen Energy Supply, LLC. This presentation has been applied where identification of particular subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a particular entity is considered important to understanding the matter being disclosed, the specific entity's name is used, in particular, for those few disclosures that apply only to Talen Energy Corporation. References, individually, toTalen Energy Corporation and Talen Energy Supply, LLC are references to such entities directly or to one or more of their subsidiaries, as the case may be, the financial results of which subsidiaries are consolidated into such registrant's financial results in accordance with GAAP. However, specific references to Talen Energy Supply, LLC also apply to Talen Energy Corporation through consolidation.

TABLE OF CONTENTS
Item Page
PART I
 EXPLANTORY NOTE
i
 GLOSSARY OF TERMS AND ABBREVIATIONS
ii
 FORWARD-LOOKING INFORMATION
1
1.Business
3
1A.Risk Factors
16
1B.Unresolved Staff Comments
27
2.Properties
28
3.Legal Proceedings
29
4.Mine Safety Disclosures
29
 PART II 
5.Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
30
6.Selected Financial Data
31
7.Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
32
 Overview
32
 Results of Operations
37
 Financial Condition
46
 New Accounting Guidance
56
 Application of Critical Accounting Policies
56
 Other Information
61
7A.Quantitative and Qualitative Disclosures About Market Risk
62
 Reports of Independent Registered Public Accounting Firm
63
   


This combined Form 10-K is separately filedTable of Contents

8.Financial Statements and Supplementary Data
66
 FINANCIAL STATEMENTS 
 Talen Energy Corporation and Subsidiaries 
 Consolidated Statements of Income
66
 Consolidated Statements of Comprehensive Income
67
 Consolidated Statements of Cash Flows
68
 Consolidated Balance Sheets
69
 Consolidated Statements of Equity
71
 Talen Energy Supply, LLC and Subsidiaries 
 Consolidated Statements of Income
72
 Consolidated Statements of Comprehensive Income
73
 Consolidated Statements of Cash Flows
74
 Consolidated Balance Sheets
75
 Consolidated Statements of Equity
77
 COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
 1. Summary of Significant Accounting Policies
78
 2. Segment and Related Information
89
 3. Earnings (Loss) Per Share for Talen Energy Corporation
91
 4. Income and Other Taxes
91
 5. Financing Activities
94
 6. Acquisitions, Development and Divestitures
97
 7. Leases
101
 8. Stock-Based Compensation
101
 9. Retirement and Postemployment Benefits
103
 10. Jointly Owned Facilities
112
 11. Commitments and Contingencies
112
 12. Related Party Transactions
118
 13. Other Income (Expense) - net
119
 14. Fair Value Measurements and Credit Concentration
119
 15. Derivative Instruments and Hedging Activities
124
 16. Goodwill and Other Asset Impairments
129
 17. Other Intangible Assets
130
 18. Asset Retirement Obligations
131
 19. Available-for-Sale Securities
132
 20. Accumulated Other Comprehensive Income (Loss)
133
 21. New Accounting Guidance Pending Adoption
134
 SUPPLEMENTARY DATA 
 Schedule I - Talen Energy Corporation Condensed Unconsolidated Financial Statements
137
 Quarterly Financial and Common Stock Price - Talen Energy Corporation
141
9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
142
9A.Controls and Procedures
142
9B.Other Information
143
   


Table of Contents

 PART III 
10.Directors, Executive Officers and Corporate Governance
143
11.Executive Compensation
145
12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
145
13.Certain Relationships and Related Transactions, and Director Independence
146
14.Principal Accounting Fees and Services
146
 PART IV 
15.Exhibits, Financial Statement Schedules
147
 Signatures
148
 Exhibit Index
150


Table of Contents

EXPLANATORY NOTE

In June 2014, PPL and Talen Energy Supply executed definitive agreements with the Riverstone Holders to combine their competitive power generation businesses into a new, stand-alone, publicly traded company named Talen Energy Corporation. On June 1, 2015, PPL completed the spinoff to PPL shareowners of a newly formed entity, Talen Energy Holdings, Inc. (Holdco), which at such time owned all of the membership interests of Talen Energy Supply and all of the common stock of Talen Energy Corporation. Immediately following the spinoff, Holdco merged with a special purpose subsidiary of Talen Energy Corporation, with Holdco continuing as the surviving company to the merger and as a wholly owned subsidiary of Talen Energy Corporation and the sole owner of Talen Energy Supply. PPL does not have an ownership interest in Talen Energy Corporation or Talen Energy Supply after completion of the spinoff. Substantially contemporaneous with the spinoff and merger, RJS Power was contributed by the following individual registrants:  PPL Corporation, PPLRiverstone Holders to become a subsidiary of Talen Energy Supply LLC, PPL Electric Utilities Corporation, LG&E and KU(referred to as the "combination" or the "acquisition"). Subsequent to the acquisition, RJS Power was merged into Talen Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company.  Information contained herein relating to PPLSupply. Talen Energy has treated the combination with RJS Power as an acquisition, with Talen Energy Supply LLC, PPL Electric Utilities Corporation, LG&Econsidered the accounting acquirer, in accordance with business combination accounting guidance. See Notes 1, 3 and KU6 to the Financial Statements for additional information on the spinoff and acquisition.

Talen Energy LLC, Louisville GasCorporation's obligation to report under the Securities and Electric Company and Kentucky Utilities Company is filed by PPL Corporation and separately by PPLExchange Act of 1934, as amended, commenced on May 1, 2015, the date Talen Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities CompanyCorporation's Registration Statement on their own behalf.  No registrant makes any representation as to information relating to any other registrant, except that informationForm S-1 relating to the five PPLspinoff transaction was declared effective by the SEC. Talen Energy Supply is a separate registrant and considered the predecessor of Talen Energy Corporation, subsidiaries is also attributedtherefore, the financial information prior to PPL Corporation and the information relating to Louisville Gas and Electric Company and Kentucky Utilities Company is also attributed to LG&E and KU Energy LLC.

Unless otherwise specified, referencesJune 1, 2015 presented in this Annual Report on Form 10-K individually, to PPL Corporation, PPLfor both registrants includes only legacy Talen Energy Supply LLC, PPL Electric Utilities Corporation, LG&Einformation. From June 1, 2015, upon completion of the spinoff and KUacquisition, Talen Energy LLC, Louisville GasCorporation's and Electric Company or Kentucky Utilities Company are references to such entities directly or to one or more of their subsidiaries, as the case may be, the financial results of which areTalen Energy Supply's consolidated into such Registrants in accordance with GAAP.  This presentation has been applied where identification of particular subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information also includes RJS. As such, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information presented in this Annual Report on aForm 10-K for 2015 represents twelve months of legacy Talen Energy Supply information consolidated basis.with seven months of RJS information from June 1, 2015, while 2014 and earlier periods represent only legacy Talen Energy Supply information.


Item  Page
  PART I 
  
Glossary of Terms and Abbreviations
i
  
Forward-Looking Information
1
1.
 
Business
3
1A.
 
Risk Factors
22
1B.
 
Unresolved Staff Comments
34
2.
 
Properties
35
3.
 
Legal Proceedings
38
4.
 
Mine Safety Disclosures
38
    
  PART II 
5.
 
Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
39
6.
 
Selected Financial and Operating Data
41
7. Management's Discussion and Analysis of Financial Condition and Results of Operations 
  
PPL Corporation and Subsidiaries
43
  
PPL Energy Supply, LLC and Subsidiaries
91
  
PPL Electric Utilities Corporation and Subsidiaries
119
  
LG&E and KU Energy LLC and Subsidiaries
135
  
Louisville Gas and Electric Company
156
  
Kentucky Utilities Company
175
7A.
 
Quantitative and Qualitative Disclosures About Market Risk
194
  
Reports of Independent Registered Public Accounting Firms
196

i

Table of Contents


8.Financial Statements and Supplementary Data
FINANCIAL STATEMENTS
PPL Corporation and Subsidiaries
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010
209
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
210
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
211
Consolidated Balance Sheets at December 31, 2012 and 2011
212
Consolidated Statements of Equity for the years ended December 31, 2012, 2011 and 2010
214
PPL Energy Supply, LLC and Subsidiaries
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010
215
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
216
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
217
Consolidated Balance Sheets at December 31, 2012 and 2011
218
Consolidated Statements of Equity for the years ended December 31, 2012, 2011 and 2010
220
PPL Electric Utilities Corporation and Subsidiaries
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010
222
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
223
Consolidated Balance Sheets at December 31, 2012 and 2011
224
Consolidated Statements of Shareowners' Equity for the years ended December 31, 2012, 2011 and 2010
226
LG&E and KU Energy LLC and Subsidiaries
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010
227
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
228
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
229
Consolidated Balance Sheets at December 31, 2012 and 2011
230
Consolidated Statements of Equity for the years ended December 31, 2012, 2011 and 2010
232
Louisville Gas and Electric Company
Statements of Income for the years ended December 31, 2012, 2011 and 2010
233
Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
234
Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
235
Balance Sheets at December 31, 2012 and 2011
236
Statements of Equity for the years ended December 31, 2012, 2011 and 2010
238
Kentucky Utilities Company
Statements of Income for the years ended December 31, 2012, 2011 and 2010
239
Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010
240
Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010
241
Balance Sheets at December 31, 2012 and 2011
242
Statements of Equity for the years ended December 31, 2012, 2011 and 2010
244
COMBINED NOTES TO FINANCIAL STATEMENTS
1.   Summary of Significant Accounting Policies
245
2.   Segment and Related Information
261
3.   Preferred Securities
264
4.   Earnings Per Share
265
5.   Income and Other Taxes
266
6.   Utility Rate Regulation
280
7.   Financing Activities
289
8.   Acquisitions, Development and Divestitures
299
9.   Discontinued Operations
301
10.  Business Acquisitions
303
11.  Leases
309
12.  Stock-Based Compensation
311
13.  Retirement and Postemployment Benefits
316
14.  Jointly Owned Facilities
338
15.  Commitments and Contingencies
340
16.  Related Party Transactions
358
17.  Other Income (Expense) - net
361
18.  Fair Value Measurements and Credit Concentration
362



  
19.  Derivative Instruments and Hedging Activities
370
  
20.  Goodwill and Other Intangible Assets
383
  
21.  Asset Retirement Obligations
387
  
22.  Variable Interest Entities
388
  
23.  Available-for-Sale Securities
389
  
24.  New Accounting Guidance Pending Adoption
390
    
  SUPPLEMENTARY DATA 
  Schedule I - Condensed Unconsolidated Financial Statements 
  
LG&E and KU Energy LLC
392
  
Quarterly Financial, Common Stock Price and Dividend Data - PPL Corporation
396
  
Quarterly Financial Data - PPL Electric Utilities Corporation
397
9.
 
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
398
9A.
 
Controls and Procedures
398
9B.
 
Other Information
399
    
  PART III 
10.
 
Directors, Executive Officers and Corporate Governance
400
11.
 
Executive Compensation
402
12.
 
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
402
13.
 
Certain Relationships and Related Transactions, and Director Independence
403
14.
 
Principal Accounting Fees and Services
403
    
  PART IV 
15.
 
Exhibits, Financial Statement Schedules
405
  
Shareowner and Investor Information
406
  
Signatures
408
  
Exhibit Index
414
  
Computation of Ratio of Earnings to Fixed Charges
433
  
Certifications of Principal Executive Officer and Principal Financial Officer Pursuant to Section 302 of
  the Sarbanes-Oxley Act of 2002
439
  
Certificates of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of
  the Sarbanes-Oxley Act of 2002
451


GLOSSARY OF TERMS AND ABBREVIATIONS

PPL CorporationTalen Energy and its current and former subsidiaries

Central NetworksAthens - collectively Central Networks East plc, Central Networks Limited and certain other related assets and liabilities.  On April 1, 2011, PPL WEM Holdings plc (formerly WPD Investment Holdings Limited) purchased allNew Athens Generating Company, LLC, an indirect subsidiary of the outstanding ordinary share capital of these companies from E.ON AG subsidiaries.  Central Networks West plc (subsequently renamed Western Power Distribution (West Midlands) plc), wholly owned by Central Networks Limited (subsequently renamed WPD Midlands Holdings Limited), and Central Networks East plc (subsequently renamed Western Power Distribution (East Midlands) plc) are British regional electricity distribution utility companies.Talen Energy Supply that owns generating operations in New York.

Harquahala KU- Kentucky UtilitiesNew Harquahala Generating Company, a public utilityLLC, an indirect subsidiary of LKE engagedTalen Energy Supply that owns generating operations in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky.  The subsidiary was acquired by PPL through the acquisition of LKE in November 2010.Arizona.

Holdco LG&E- Louisville Gas and Electric Company,Talen Energy Holdings, Inc., a public utility subsidiaryDelaware corporation, which was formed for the purposes of LKE engaged in the regulated generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas in Kentucky.  The subsidiary was acquired by PPL through the acquisition of LKE in November 2010.spinoff transaction.

JadeLKE - LG&E and KU EnergyJade Power Generation Holdings LLC, (formerly E.ON U.S. LLC), a subsidiary of PPLTalen Energy Supply that, through its subsidiaries, owns generating operations in Texas.

MACH Gen - MACH Gen, LLC, a subsidiary of Talen Energy Supply and the parent of LG&E, KUNew MACH Gen.

Millennium - Millennium Power Partners, L.P., an indirect subsidiary of Talen Energy Supply that owns generating operations in Massachusetts.

New MACH Gen - New MACH Gen, LLC, an indirect subsidiary of Talen Energy Supply and other subsidiaries.  PPL acquired E.ON U.S.a direct subsidiary of MACH Gen that, through its subsidiaries, owns generating operations in Arizona, Massachusetts and New York.

Raven - Raven Power Generation Holdings LLC, a subsidiary of Talen Energy Supply that, through its subsidiaries, owns generating operations in November 2010Maryland.

RJS - Raven, Jade and changedSapphire, collectively.

RJS Power - RJS Generation Holdings LLC, a Delaware limited liability company and former parent of RJS that was contributed by the nameRiverstone Holders to LG&ETalen Energy on June 1, 2015 in exchange for 35% of Talen Energy Corporation's common stock. Following the contribution, RJS Power was merged into Talen Energy Supply.
Sapphire - Sapphire Power Generation Holdings LLC, a subsidiary of Talen Energy Supply that owns generating operations in Massachusetts, New Jersey and KUPennsylvania.

Susquehanna Nuclear - Susquehanna Nuclear, LLC, a subsidiary of Talen Generation that owns a nuclear-powered generating station in Pennsylvania.

Talen Energy- Talen Energy Corporation and Talen Energy Supply, LLC.

LKSTalen Energy Corporation- LG&Ea publicly traded Delaware corporation and KU Services Company (formerly E.ON U.S. Services Inc.), a subsidiarythe indirect parent of LKE that provides services for LKE and its subsidiaries.  The subsidiary was acquired by PPL throughTalen Energy Supply following the acquisition of LKE in November 2010.spinoff from PPL.

Talen Energy SupplyPPL - Talen Energy Supply, LLC, formerly PPL Energy Supply, LLC, an indirect subsidiary of Talen Energy Corporation and the parent holding company of PPL Electric, PPLTalen Generation, Talen Energy Funding, LKEMarketing, RJS and other subsidiaries.

Talen Energy MarketingPPL Brunner Island - PPL Brunner Island,Talen Energy Marketing, LLC, a subsidiary of PPL Generation that owns generating operations in Pennsylvania.

PPL Capital Funding - PPL Capital Funding, Inc., a wholly owned financing subsidiary of PPL that provides financing for the operations of PPL and certain subsidiaries.  Debt issued by PPL Capital Funding is guaranteed as to payment by PPL.

PPL Electric - PPL Electric Utilities Corporation, a public utility subsidiary of PPL that transmits and distributes electricity in its Pennsylvania service area and provides electric supply to retail customers in this area as a PLR.

PPL Energy Funding - PPL Energy Funding Corporation, a subsidiary of PPL and the parent holding company of PPL Energy Supply, PPL Global (effective January 2011) and other subsidiaries.

PPL EnergyPlus -formerly PPL EnergyPlus, LLC, a subsidiary of PPLTalen Energy Supply that markets and trades wholesale and retail electricity and gas, and supplies energy and energy services in competitive markets.

Talen GenerationPPL Energy Supply - PPL Energy Supply, LLC, a subsidiary of PPL Energy Funding and the parent company of PPL Generation, PPL EnergyPlus and other subsidiaries.  In January 2011, PPL Energy Supply distributed its membership interest in PPL Global, representing 100% of the outstanding membership interests of PPL Global, to PPL Energy Supply's parent, PPL Energy Funding.

PPL Generation - PPLTalen Generation, LLC, a subsidiary of PPLTalen Energy Supply that owns and operates U.S. generating facilities through various subsidiaries.

PPL Global - PPL Global, LLC, a subsidiary of PPL Energy Funding thatsubsidiaries primarily owns and operates WPD a business in the U.K., that is focused on the regulated distribution of electricity.  In January 2011, PPL Energy Supply, PPL Global's former parent, distributed its membership interest in PPL Global, representing 100% of the outstanding membership interest of PPL Global, to its parent, PPL Energy Funding.

PPL Holtwood - PPL Holtwood, LLC, a subsidiary of PPL Generation that owns hydroelectric generating operations in Pennsylvania.

Talen MontanaPPL Ironwood -- PPL IronwoodTalen Montana, LLC, an indirect subsidiary of PPLTalen Generation that owns generating operations in Pennsylvania.

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PPL Martins Creek - PPL Martins Creek, LLC, a subsidiary of PPL Generation that owns generating operations in Pennsylvania.Montana.

Talen Renewable EnergyPPL Montana - PPL Montana,Talen Renewable Energy, LLC, an indirecta former subsidiary of PPL GenerationTalen Energy Supply that generates electricity for wholesale sales in Montana and the Pacific Northwest.owned Talen Energy's renewable energy business.

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PPL Montour - PPL Montour, LLC, a subsidiaryTable of PPL Generation that owns generating operations in Pennsylvania.Contents

PPL Services - PPL Services Corporation, a subsidiary of PPL that provides services for PPL and its subsidiaries.

PPL Susquehanna - PPL Susquehanna, LLC, the nuclear generating subsidiary of PPL Generation.

PPL WEM - PPL WEM Holdings plc (formerly WPD Investment Holdings Limited), an indirect U.K. subsidiary of PPL Global.  PPL WEM indirectly owns both WPD (East Midlands) and WPD (West Midlands).

PPL WW - PPL WW Holdings Limited (formerly Western Power Distribution Holdings Limited), an indirect U.K. subsidiary of PPL Global.  PPL WW Holdings indirectly owns WPD (South Wales) and WPD (South West).

WPD - refers to PPL WW and PPL WEM and their subsidiaries.

WPD (East Midlands) - Western Power Distribution (East Midlands) plc, a British regional electricity distribution utility company.  The company (formerly Central Networks East plc) was acquired and renamed in April 2011.

WPD Midlands- refers to Central Networks, which was renamed after the acquisition.

WPD(South Wales) - Western Power Distribution (South Wales) plc, a British regional electricity distribution utility company.

WPD(South West) - Western Power Distribution (South West) plc, a British regional electricity distribution utility company.

WPD (West Midlands) - Western Power Distribution (West Midlands) plc, a British regional electricity distribution utility company.  The company (formerly Central Networks West plc) was acquired and renamed in April 2011.

WKE - Western Kentucky Energy Corp., a subsidiary of LKE that leased certain non-utility generating plants in western Kentucky until July 2009.  The subsidiary was acquired by PPL through the acquisition of LKE in November 2010.

Other terms and abbreviations

£ - British pound sterling.

1945 First Mortgage Bond - PPL Electric's Mortgage and Deed of Trust, dated as of October 1, 1945, to Deutsche Bank Trust Company Americas, as trustee, as supplemented.

2001 Mortgage Indenture - PPL Electric's Indenture, dated as of August 1, 2001, to The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as trustee, as supplemented.

2010 Bridge Facility - an up to $6.5 billion Senior Bridge Term Loan Credit Agreement between PPL Capital Funding, as borrower, and PPL, as guarantor, and a group of banks syndicated in June 2010, to serve as a funding backstop in the event alternative financing was not available prior to the closing of PPL's acquisition of E.ON U.S. LLC.

2010 Equity Unit(s) - a PPL equity unit, issued in June 2010, consisting of a 2010 Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.625% Junior Subordinated Notes due 2018.

2010 Purchase Contract(s) - a contract that is a component of a 2010 Equity Unit that requires holders to purchase shares of PPL common stock on or prior to July 1, 2013.
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2011 Bridge Facility - the £3.6 billion Senior Bridge Term Loan Credit Agreement between PPL Capital Funding and PPL WEM, as borrowers, and PPL, as guarantor, and lenders party thereto, used to fund the April 1, 2011 acquisition of Central Networks, as amended by Amendment No. 1 thereto dated April 15, 2011.

2011 Equity Unit(s) - a PPL equity unit, issued in April 2011, consisting of a 2011 Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.32% Junior Subordinated Notes due 2019.

2011 Purchase Contract(s) - a contract that is a component of a 2011 Equity Unit that requires holders to purchase shares of PPL common stock on or prior to May 1, 2014.

401(h) account - Aa sub-account established within a qualified pension trust to provide for the payment of retiree medical costs.

Adjusted EBITDAAct 11 - Act 11see Item 7. Combined Management's Discussion and Analysis of 2012 that became effective on April 16, 2012.  The Pennsylvania legislation authorizes the PUC to approve two specific ratemaking mechanisms:  the useFinancial Condition and Results of a fully projected future test year in base rate proceedingsOperations - Statement of Income Analysis, Margins, EBITDA and subject to certain conditions, a DSIC.Adjusted EBITDA - EBITDA and Adjusted EBITDA.

Amended STF Agreement Act 129- Act 129Amended and Restated Common Agreement dated as of 2008 that became effective in October 2008.  The law amendsDecember 15, 2015, among Talen Energy Marketing, Talen Energy Supply, as guarantor, Brunner Island, LLC, Montour, LLC, Wilmington Trust, National Association, as agent, and the Pennsylvania Public Utility Code and creates an energy efficiency and conservation program and smart metering technology requirements, adopts new PLR electricity supply procurement rules, provides remedies for market misconduct and makes changes to the AEPS.secured counterparties thereto.

AEPS - Alternative Energy Portfolio Standard.

AFUDC - Allowance for Funds Used During Construction, the cost of equity and debt funds used to finance construction projects of regulated businesses, which is capitalized as part of construction costs.

AOCI - accumulated other comprehensive income or loss.

ARO - asset retirement obligation.

Baseload generation - includes the output provided by PPL's nuclear, coal, hydroelectric and qualifying facilities.

Basis - when used in the context of derivatives and commodity trading, the commodity price differential between two locations, products or time periods.times.

CCR(s)Bcf - billion cubic feet.Coal Combustion Residual(s), including fly ash, bottom ash and sulfur dioxide scrubber wastes.

Black Lung Trust - a trust account maintained under federal and state Black Lung legislation for the payment of claims related to disability or death due to pneumoconiosis.

Bluegrass CTs - three natural gas combustion turbines owned by Bluegrass Generation.  In 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of these combustion turbines, subject to certain conditions including receipt of applicable regulatory approvals and clearances.  In June 2012, LG&E and KU terminated the asset purchase agreement.

Bluegrass Generation - Bluegrass Generation Company, L.L.C., an exempt wholesale electricity generator in LaGrange, Kentucky.

BREC - Big Rivers Electric Corporation, a power-generating rural electric cooperative in western Kentucky.

Cane Run Unit 7 - a combined cycle natural gas unit under construction in Kentucky, jointly owned by LG&E and KU, which is expected to provide additional electric generating capacity of 141 MW and 499 MW to LG&E and KU by 2015.

CAIR - the EPA's Clean Air Interstate Rule.

Clean Air Act - federal legislation enacted to address certain environmental issues related to air emissions, including acid rain, ozone and toxic air emissions.

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COBRA - Consolidated Omnibus Budget Reconciliation Act.

COLA - license application for a combined construction permit and operating license from the NRC for a nuclear plant.

CRRsCPCN -- Certificate congestion revenue rights, which are financial instruments established to manage price risk related to electricity transmission congestion that entitle the holder to receive compensation or require the holder to remit payment for certain congestion-related transmission charges based on the level of Public Conveniencecongestion between two pricing locations, known as source and Necessity.  Authority granted by the KPSC pursuant to Kentucky Revised Statute 278.020 to provide utility service to or for the public or the construction of certain plant, equipment, property or facility for furnishing of utility service to the public.sink.

CSAPR -Cross-State Air Pollution Rule.

Customer Choice Act - the Pennsylvania Electricity Generation Customer Choice and Competition Act, legislation enacted to restructure the state's electric utility industry to create retail access to a competitive market for generation of electricity.

DDCP - Directors Deferred Compensation Plan.

Depreciation not normalized - the flow-through income tax impact related to the state regulatory treatment of depreciation-related timing differences.

DNO - Distribution Network Operator.

Dodd-Frank Act - the Dodd-Frank Wall Street Reform and Consumer Protection Act that was signed into law in July 2010.

DOE - U.S. Department of Energy, a U.S. government agency.Energy.

DPCR4DR - Distribution Price Control Review 4, demand response, a program designed to induce, through the U.K. 5-year rate review period applicableuse of incentive payments, retail electricity consumers to WPD that commenced April 1, 2005.lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.

EBITDADPCR5 - Distribution Price Control Review 5, the U.K. 5-year rate review period applicable to WPD that commenced April 1, 2010.see Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Statement of Income Analysis, Margins, EBITDA and Adjusted EBITDA - EBITDA and Adjusted EBITDA.

DRIPELG - Dividend Reinvestment and Direct Stock Purchase Plan.Effluent Limitations Guidelines.

EPADSIC - a distribution system improvement charge authorized under Act 11, which is an alternative ratemaking mechanism providing more-timely cost recovery of qualifying distribution system capital expenditures.U.S. Environmental Protection Agency.

DSMEPS - Demand Side Management.  Pursuant to Kentucky Revised Statute 278.285, the KPSC may determine the reasonableness of DSM plans proposed by any utility under its jurisdiction.  Proposed DSM mechanisms may seek full recovery of DSM programs and revenues lost by implementing those programs and/or incentives designed to provide financial rewards to the utility for implementing cost-effective DSM programs.  The cost of such programs shall be assigned only to the class or classes of customers which benefit from the programs.

DUoS - Distribution Use of System.  This forms the majority of WPD's revenues and is the charge to electricity suppliers who are WPD's customers and use WPD's network to distribute electricity.

EBPB - Employee Benefit Plan Board. The administrator of PPL's U.S. qualified retirement plans, which is charged with the fiduciary responsibility to oversee and manage those plans and the investments associated with those plans.

Economic Stimulus Package - The American Recovery and Reinvestment Act of 2009, generally referred to as the federal economic stimulus package, which was signed into law in February 2009.

ECR - Environmental Cost Recovery.  Pursuant to Kentucky Revised Statute 278.183, effective January 1993, Kentucky electric utilities are entitled to the current recovery of costs of complying with the Clean Air Act, as amended, and those federal, state or local environmental requirements which apply to coal combustion and by-products from the production of energy from coal.

EEI - Electric Energy, Inc., owns and operates a coal-fired plant and a natural gas facility in southern Illinois.  KU's 20% ownership interest in EEI is accounted for as an equity method investment.

E.ON AG - a German corporation and the parent of E.ON UK plc, the former parent of Central Networks, and the indirect parent of E.ON US Investments Corp., the former parent of LKE.

EPA - Environmental Protection Agency, a U.S. government agency.

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EPS - earnings per share.

ERCOTEquity Units - refers collectively to the 2011Electric Reliability Council of Texas, operator of the electricity transmission network and 2010 Equity Units.electricity energy market in most of Texas.

ESOP - Employee Stock Ownership Plan.

Euro - the basic monetary unit among participating members of the European Union.

EWG - exempt wholesale generator.

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FERCE.W. Brown - a generating station in Kentucky with capacity of 1,594 MW.U.S. Federal Energy Regulatory Commission.

FERC - Federal Energy Regulatory Commission, the federal agency that regulates, among other things, interstate transmission and wholesale sales of electricity, hydroelectric power projects and related matters.

Fitch - Fitch, Inc., a credit rating agency.

FTR(s)FTRs - financial transmission right,rights, which is aare financial instrumentinstruments established to manage price risk related to electricity transmission congestion that entitlesentitle the holder to receive compensation or requiresrequire the holder to remit payment for certain congestion-related transmission charges based on the level of congestion in the transmission grid.between two pricing locations, known as source and sink.

First Lien Credit and Guaranty AgreementFundamental Change- the First Lien Credit and Guaranty Agreement dated as it relates toof April 28, 2014, among New MACH Gen, as borrower, the terms ofguarantors named therein, the 2011lenders party thereto and 2010 Equity Units, will be deemed to have occurred if any of the following occurs with respect to PPL, subject to certain exceptions:  (i) a change of control; (ii) a consolidation with or merger into any other entity; (iii) common stock ceases to be listed or quoted; or (iv) a liquidation, dissolution or termination.CLMG Corp., as administrative agent.

GAAP - Generally Accepted Accounting Principles in the U.S.

GBP - British pound sterling.

GHG - greenhouse gas(es).

GWh - gigawatt-hour, one million kilowatt-hours.

IBEW Health Care Reform - The Patient Protection and Affordable Care Act (HR 3590) and the Health Care and Education Reconciliation Act of 2010 (HR 4872), signed into law in March 2010.

HMRC - Her Majesty's Revenue & Customs.  The tax authority in the U.K., formerly known as Inland Revenue.

IBEW- International Brotherhood of Electrical Workers.

Ironwood FacilityICP - Incentive Compensation Plan.a natural gas combined-cycle unit in Lebanon, Pennsylvania.

ICPKEIRS - Incentive Compensation Plan for Key Employees.U.S. Internal Revenue Service.

Intermediate and peaking generation - includes the output provided by PPL's oil- and natural gas-fired units.

Ironwood Acquisition - In April 2012, PPL Ironwood Holdings, LLC, an indirect, wholly owned subsidiary of PPL Energy Supply, completed the acquisition from a subsidiary of The AES Corporation of all of the equity interests of AES Ironwood, L.L.C. (subsequently renamed PPL Ironwood, LLC) and AES Prescott, L.L.C. (subsequently renamed PPL Prescott, LLC), which own and operate, respectively, the Ironwood Facility.

Ironwood Facility - a natural gas-fired power plant in Lebanon, Pennsylvania with a summer rating of 665 MW.

IRS - Internal Revenue Service, a U.S. government agency.

ISO - Independent System Operator.

KPSC - Kentucky Public Service Commission, the state agency that has jurisdiction over the regulation of rates and service of utilities in Kentucky.

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KU 2010 Mortgage IndentureISO-NE - KU's Indenture dated as of October 1, 2010, to The Bank ofISO New York Mellon, as trustee, as supplemented.England Inc., oversees the bulk power generation and transmission system that serves Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

kVA - kilovolt ampere.

kWh - kilowatt-hour, basic unit of electrical energy.

LCIDALIBOR - Lehigh County Industrial Development Authority.

LG&E 2010 Mortgage Indenture - LG&E's Indenture, dated as of October 1, 2010, to The Bank of New York Mellon, as trustee, as supplemented.

LIBOR - London Interbank Offered Rate.

Long Island generation business - includes a 79.9 MW gas-fired plant in the Edgewood section of Brentwood, New York and a 79.9 MW oil-fired plant in Shoreham, New York and related tolling agreements.  This business was sold in February 2010.

LTIIP - Long Term Infrastructure Improvement Plan.

MATS -Mercury and Air Toxics Standards.

MDE - Maryland Department of Environment.

MDEQ - Montana Department of Environmental Quality.

MEIC - Montana Environmental Information Center.

MMBtu - One million British Thermal Units.

Montana Power - The Montana Power Company, a Montana-based company that sold its generating assets to PPL Montana in December 1999.  Through a series of transactions consummated during the first quarter of 2002, Montana Power sold its electricity delivery business to NorthWestern.

Moody's - Moody's Investors Service, Inc., a credit rating agency.

MW - megawatt, one thousand kilowatts.

MWh - megawatt-hour, one thousand kilowatt-hours.

NAAQS- National Ambient Air Quality Standard.

NDT - PPL Susquehanna's nuclearSusquehanna Nuclear's plant decommissioning trust.

NERC - North American Electric Reliability Corporation.

New MACH Gen RCF - revolving credit facility within the First Lien Credit and Guaranty Agreement.


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NorthWestern- NorthWestern Corporation, a Delaware corporation, and successor in interest to Montana Power's electricity delivery business, including Montana Power's rights and obligations under contracts with PPLTalen Montana.

NPDES - National Pollutant Discharge Elimination System.

NPNS - the normal purchases and normal sales exception as permitted by derivative accounting rules. Derivatives that qualify for this exception may receive accrual accounting treatment.

NRC - U.S. Nuclear Regulatory Commission, the federal agency that regulates nuclear power facilities.Commission.

NYISONUGs - non-utility generators, generating plants not owned by public utilities, whose electrical output must be purchased by utilities under the PURPA ifNew York Independent System Operator, which operates competitive wholesale markets to manage the plant meets certain criteria.flow of electricity across New York.

OCI - other comprehensive income or loss.

Ofgem - Office of Gas and Electricity Markets, the British agency that regulates transmission, distribution and wholesale sales of electricity and related matters.
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Opacity - the degree to which emissions reduce the transmission of light and obscure the view of an object in the background. There are emission regulations that limit the opacity inof power plant stack gas emissions.

OVEC PADEP- Ohio Valley Electric Corporation, located in Piketon, Ohio, an entity in which LKE indirectly owns an 8.13% interest (consists of LG&E's 5.63% and KU's 2.50% interests), which is accounted for as a cost-method investment.  OVEC owns and operates two coal-fired power plants, the Kyger Creek plant in Ohio and the Clifty Creek plant in Indiana, with combined nameplate capacities of 2,390 MW.

PADEP - the Pennsylvania Department of Environmental Protection, a state government agency.Protection.

PEDFA- Pennsylvania Economic Development Financing Authority.

PJM - PJM Interconnection, L.L.C., operator of the electricelectricity transmission network and electric energyelectricity market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

PLR - Provider of Last Resort, the role of PPL Electric in providing default electricity supply to retail customers within its delivery area to retail customers who have not chosen to select an alternative electricity supplier under the Customer Choice Act.

PP&E - property, plant and equipment.

PPLPredecessor - refersPPL Corporation, the former indirect parent holding company of Talen Energy and its subsidiaries prior to the LKE, LG&E and KU pre-acquisition activity coveringcompletion of the time period prior to November 1, 2010.spinoff.

PPL Electric- PPL Electric Utilities Corporation, a public utility subsidiary of PPL and former affiliate of Talen Energy engaged in the regulated transmission and distribution of electricity in its Pennsylvania service area and that provides electricity supply to its retail customers in this area as a PLR.

PPL Services - PPL Services Corporation, a subsidiary of PPL and former affiliate of Talen Energy that provided services prior to the spinoff and currently provides services under a transition services agreement.

PUC - Pennsylvania Public Utility Commission, the state agency that regulates certain ratemaking, services, accounting and operations of Pennsylvania utilities.

PUCTPUC Final Order - final order issued by the PUC on August 27, 1998, approving the settlementPublic Utility Commission of PPL Electric's restructuring proceeding.Texas.

RCRAPUHCA - Public Utility Holding CompanyResource Conservation and Recovery Act of 1935, repealed effective February 2006 by the Energy Policy Act of 2005 and replaced with the Public Utility Holding Company Act of 2005.1976.

RECsPurchase Contract(s) - refers collectively to the 2010 and 2011 Purchase Contracts.Renewable Energy Credits.

Regional Haze ProgramPURPA - Public Utility Regulatory Policies Act of 1978, legislation passed by the U.S. CongressEPA program that requires states to encourage energy conservation, efficient use of resourcesdevelop and equitable rates.implement air quality protection plans to reduce pollution that causes visibility impairment in national parks and wilderness areas.

RGGIPURTA - The Pennsylvania Public Utility Realty Tax Act.Regional Greenhouse Gas Initiative.

RiverstoneRAV - regulatory asset value.  This term is also commonly known as RAB or regulatory asset base.Riverstone Holdings LLC, a Delaware limited liability company.

Riverstone HoldersRECs - renewable energy credits.Raven Power Holdings LLC, C/R Energy Jade, LLC and Sapphire Power Holdings LLC, affiliates of Riverstone that formerly owned RJS Power and contributed RJS Power to Talen Energy on June 1, 2015 in exchange for 35% of Talen Energy Corporation's common stock.


Regional Transmission Expansion Plan - PJM conducts a long-range Regional Transmission Expansion Planning process that identifies what changes and additions to the grid are needed to ensure future needs are met for both the reliability and the economic performance of the grid.  Under PJM agreements, transmission owners are obligated to build transmission projects that are needed to maintain reliability standards and that are reviewed and approved by the PJM Board.
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Registrants - PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU, collectively.

Regulation S-X - SEC regulation governing the form and contentTable of and requirements for financial statements required to be filed pursuant to the federal securities laws.Contents

RFC - Reliability First Corporation, one of eight regional entities with delegated authority from NERC that work to safeguard the reliability of the bulk power systems throughout North America.

RFP - Request for Proposal.

RMC - Risk Management Committee.

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RTO- Regional Transmission Organization.

S&P - Standard & Poor's Ratings Services, a credit rating agency.

Sarbanes-Oxley - Sarbanes-Oxley Act of 2002, which sets requirements for management's assessment of internal controls for financial reporting. It also requires an independent auditor to make its own assessment.

SCR - selective catalytic reduction, a pollution control process for the removal of nitrogen oxide from exhaust gases.

Scrubber - an air pollution control device that can remove particulates and/or gases (primarily sulfur dioxide) from exhaust gases.

SEC - the U.S. Securities and Exchange Commission, a U.S. government agency whose primary mission is to protect investors and maintain the integrity of the securities markets.Commission.

Securities Act of 1933 - the Securities Act of 1933, 15 U.S. Code, Sections 77a-77aa, as amended.

SERC - SERC Reliability Corporation, one of eight regional entities with delegated authority from NERC that work to safeguard the reliability of the bulk power systems throughout North America.

SIFMA Index - the Securities Industry and Financial Markets Association Municipal Swap Index.

SIP - PPL Corporation's 2012 Stock Incentive Plan.

Smart meter - an electric meter that utilizes smart metering technology.

Smart metering technology - technology that can measure, among other things, time of electricity consumption to permit offering rate incentives for usage during lower cost or demand intervals.  The use of this technology also has the potential to strengthen network reliability.

SMGT - Southern Montana Electric Generation & Transmission Cooperative, Inc., a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus that was terminated effective April 1, 2012.
SNCR - selective non-catalytic reduction, a pollution control process for the removal of nitrogen oxide from exhaust gases using ammonia.

Spark Spread - a measure of gross margin representing the price of power on a per MWh basis less the equivalent measure of the natural gas cost to produce that power. This measure is used to describe the gross margin of PPL and its subsidiaries' merchantTalen Energy's competitive natural gas-fired generating fleet. This term is also used to describe a derivative contract in which PPL and itsTalen Energy subsidiaries sell power and buy natural gas on a forward basis in the same contract.

Successor - refers to the LKE, LG&E and KU post-acquisition activity covering the time period after October 31, 2010.

Superfund - federal environmental legislationstatute that addresses remediation of contaminated sites; states also have similar statutes.

TC2Talen Energy Supply RCF - Trimble County Unit 2, a coal-fired plant located in Kentucky with a net summer capacitythe $1,850,000,000 Credit Agreement dated as of 732 MW.  LKE indirectly owns a 75% interest (consists of LG&E's 14.25%June 1, 2015 among Talen Energy Supply, as borrower, the guarantors party thereto, the lenders party thereto and KU's 60.75% interests) in TC2, or 549 MW of the capacity.Citibank, N.A., as administrative agent.

Term Loan B - New MACH Gen debt secured under the First Lien Credit and Guaranty Agreement.

Tolling agreement - agreement whereby the owner of an electricelectricity generating facility agrees to use that facility to convert fuel provided by a third party into electricity for delivery back to the third party.

TSR - Total shareowner return -Stockholder Return. The change in market value of a share of the Company'sa company's common stock plus the value of all dividends paid on a share of the common stock during the applicable performance period, divided by the price of the common stock as of the beginning of the performance period.

Treasury Stock MethodTRA - Tennessee Regulatory Authority,a method applied to calculate diluted EPS that assumes any proceeds that could be obtained upon exercise of options and warrants (and their equivalents) would be used to purchase common stock at the state agency that has jurisdiction overaverage market price during the regulation of rates and service of utilities in Tennessee.relevant period.

TSAUtilization Factor - a measure reflectingas applicable, the percentage of electricity actually generatedTransition Services Agreement, dated June 1, 2015, by a plant compared withand between PPL and Talen Energy Supply and the electricity such plant could produce at full capacity when available.Transition Services Agreement, dated May 4, 2015, by and between Talen Energy Supply and Topaz Power Management, LP.

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VaR - value-at-risk, a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level.

VEBA - Voluntary Employee Benefit Association Trust, accounts for health and welfare plans for future benefit payments for employees, retirees or their beneficiaries.

VIE - variable interest entity.

Volumetric risk - the risk that the actual load volumes provided under full-requirement sales contracts could vary significantly from forecasted volumes.

WECCVSCC - Virginia State Corporation Commission, the state agency that has jurisdiction overWestern Electricity Coordinating Council, which develops and implements regional reliability standards for the regulationwestern interconnection from Canada to Mexico and includes the provinces of Virginia corporations, including utilities.

VWAP - as it relates toAlberta and British Columbia, the 2011northern portion of Baja California, Mexico and 2010 Equity Units issued by PPL, the per share volume-weighted-average price as displayed under the heading Bloomberg VWAP on Bloomberg page "PPL <EQUITY> AQR" (or its equivalent successor if such page is not available) in respectall or portions of the period from the scheduled open of trading on the relevant trading day until the scheduled close of trading on the relevant trading day (or if such volume-weighted-average price is unavailable, the market price of one share of PPL common stock on such trading day determined, using a volume-weighted-average method, by a nationally recognized independent investment banking firm retained for this purpose by PPL).14 states in between.




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FORWARD-LOOKING INFORMATION

Statements contained in this Annual ReportForm 10-K concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements whichthat are other than statements of historical fact are "forward-looking statements" within the meaning of the federal securities laws. These statements often include words such as "believe," "expect," "anticipate," "intend," "plan," "estimate," "target," "project," "forecast," "seek," "will," "may," "should," "could," "would" or similar expressions. Although the Registrants believeTalen Energy believes that the expectations and assumptions reflected in these statements are reasonable, there can be no assurance that these expectations will prove to be correct. Forward-looking statements are subject to many risks and uncertainties, and actual results may differ materially from the results discussed in forward-looking statements. In addition to the specific factors discussed in "Item 1A. Risk Factors" and in "Item 7.2. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" in this Annual Report,Form 10-K, the following are among the important factors that could cause actual results to differ materially from the forward-looking statements.statements:

·fuel supply cost and availability;
adverse economic conditions;
·continuing ability to recover fuel costs and environmental expenditures in a timely manner at LG&E and KU, and natural gas supply costs at LG&E;
changes in commodity prices and related costs;
·weather conditions affecting generation, customer energy use and operating costs;
the effectiveness of Talen Energy's risk management techniques, including hedging, with respect to electricity and fuel prices, interest rates and counterparty credit and non-performance risks;
·operation, availability and operating costs of existing generation facilities;
methods of accounting and developments in or interpretations of accounting requirements that may impact reported results, including with respect to, but not limited to, hedging activity;
·the duration of and cost, including lost revenue, associated with scheduled and unscheduled outages at our generating facilities;
operational, price and credit risks in the wholesale and retail electricity markets;
·transmission and distribution system conditions and operating costs;
Talen Energy's ability to forecast the actual load needed to perform full-requirements sales contracts;
·expansion of alternative sources of electricity generation;
weather conditions;
·laws or regulations to reduce emissions of "greenhouse" gases or the physical effects of climate change;
disruptions in fuel supply;
·collective labor bargaining negotiations;
unforeseen circumstances may impact the levels of coal inventory that Talen Energy holds;
·the outcome of litigation against the Registrants and their subsidiaries;
the performance of transmission facilities and any changes in the structure and operation of, or the pricing limitations imposed by, the RTOs and ISOs that operate those facilities;
·potential effects of threatened or actual terrorism, war or other hostilities, cyber-based intrusions or natural disasters;
blackouts due to disruptions in neighboring interconnected systems;
·the commitments and liabilities of the Registrants and their subsidiaries;
competition in the power generation market, including in the expansion of alternative sources of electricity generation and in the development of new projects, markets and technologies;
·volatility in market demand and prices for energy, capacity, transmission services, emission allowances and RECs;
federal and state legislation and regulation, including costs to comply with governmental permits and approvals;
·competition in retail and wholesale power and natural gas markets;
costs of complying with environmental and related worker health and safety laws and regulations;
·liquidity of wholesale power markets;
the impacts of climate change;
·defaults by counterparties under energy, fuel or other power product contracts;
the availability and cost of emission allowances;
·market prices of commodity inputs for ongoing capital expenditures;
changes in legislative and regulatory policy, including the promotion of renewable energy, energy efficiency, conservation and self-generation;
·capital market conditions, including the availability of capital or credit, changes in interest rates and certain economic indices, and decisions regarding capital structure;
security and safety risks associated with nuclear generation;
·stock price performance of PPL;
Talen Energy's level of indebtedness;
·volatility in the fair value of debt and equity securities and its impact on the value of assets in the NDT funds and in defined benefit plans, and the potential cash funding requirements if fair value declines;
the terms and conditions of debt instruments that may restrict Talen Energy's ability to operate its business;
·interest rates and their effect on pension, retiree medical and nuclear decommissioning liabilities, and interest payable on certain debt securities;
the performance of Talen Energy's subsidiaries and affiliates, on which its cash flow and ability to meet its debt obligations largely depend;
·volatility in or the impact of other changes in financial or commodity markets and economic conditions;
the risks inherent with variable rate indebtedness;
·new accounting requirements or new interpretations or applications of existing requirements;
disruption in financial markets;
·changes in securities and credit ratings;
Talen Energy's ability to access capital markets;
·changes in foreign currency exchange rates for British pound sterling;
acquisition or divestiture activities, including Talen Energy's ability to realize expected synergies and other benefits from such business transactions;
·current and future environmental conditions, regulations and other requirements and the related costs of compliance, including environmental capital expenditures, emission allowance costs and other expenses;
changes in technology;

·legal, regulatory, political, market or other reactions to the 2011 incident at the nuclear generating facility at Fukushima, Japan, including additional NRC requirements;
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·changes in political, regulatory or economic conditions in states, regions or countries where the Registrants or their subsidiaries conduct business;
·receipt of necessary governmental permits, approvals and rate relief;
·new state, federal or foreign legislation or regulatory developments;
·the outcome of any rate cases or other cost recovery filings by PPL Electric at the PUC or the FERC, by LG&E at the KPSC or the FERC; by KU at the KPSC, VSCC, TRA or the FERC, or by WPD at Ofgem in the U.K.;
·the impact of any state, federal or foreign investigations applicable to the Registrants and their subsidiaries and the energy industry;
·the effect of any business or industry restructuring;
·development of new projects, markets and technologies;
·performance of new ventures; and
·business dispositions or acquisitions and our ability to successfully operate acquired businesses and realize expected benefits from business acquisitions, including PPL's 2011 acquisition of WPD Midlands and 2010 acquisition of LKE.


1any failure of Talen Energy's facilities to operate as planned, including the duration of and cost, including lost revenue, associated with scheduled and unscheduled outages at Talen Energy's generating facilities;
Talen Energy's ability to optimize its competitive power generation operations and the costs associated with any capital expenditures;
significant increases in operation and maintenance expenses, such as health care and pension costs, including as a result of changes in interest rates;
the loss of key personnel, the ability to hire and retain qualified employees and the impact of collective labor bargaining negotiations;
war, armed conflicts or terrorist attacks, including cyber-based attacks;
risks associated with federal and state tax laws and regulations;
any determination that the transaction that formed Talen Energy does not qualify as a tax-free distribution under the Internal Revenue Code;
Talen Energy's ability to successfully integrate the RJS Power businesses and to achieve anticipated synergies and cost savings as a result of the spinoff transaction and combination with RJS Power;
costs of complying with reporting requirements as a newly public company and any related risks of deficiencies in disclosure controls and internal control over financial reporting as a standalone entity; and
the ability of the Riverstone Holders to exercise influence over matters requiring Board of Directors and/or stockholder approval.

Any such forward-looking statements should be considered in light of such important factors and in conjunction with other documents of the RegistrantsTalen Energy on file with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for the RegistrantsTalen Energy to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Any forward-looking statement speaks only as of the date on which such statement is made, and the Registrants undertakeTalen Energy undertakes no obligation to update the information contained in such statement to reflect subsequent developments or information.



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Table of Contents

PART I

ITEM 1. BUSINESS

GENERAL

BACKGROUNDCapitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.

PPLTalen Energy Corporation,, through its principal subsidiary Talen Energy Supply, is a North American competitive energy and power generation and marketing company headquartered in Allentown, Pennsylvania, is an energyPennsylvania. Talen Energy produces and utility holding company that was incorporated in 1994.  Through subsidiaries, PPL generatessells electricity, capacity and ancillary services from its fleet of power plants totaling approximately 17,400 MW of generating capacity. Talen Energy's portfolio of generation assets is principally located in the northeastern, northwesternNortheast, Mid-Atlantic and southeastern U.S.; markets wholesale or retail energy primarily in the northeastern and northwestern portionsSouthwest regions of the U.S.; delivers electricity to customers in Pennsylvania, Kentucky, Virginia, Tennessee and the U.K.; and delivers natural gas to customers in Kentucky. See "Item 2. Properties" for additional information on Talen Energy's plants.

PPL's overall strategy is to achieve stable, long-term growth in its regulated electricity delivery businesses through efficient operationsTalen Energy's business was formed on June 1, 2015 by the spinoff of Talen Energy Supply, the competitive power generation business owned by PPL, and strong customerthe substantially contemporaneous combination of that business with RJS Power, the competitive power generation business controlled by Riverstone Holdings LLC, under a new holding company, Talen Energy Corporation. See Notes 1, 3 and regulatory relations, and disciplined optimization of energy supply margins in its energy supply business while mitigating volatility in both cash flows and earnings.

In pursuing this strategy, in 2011 and 2010, PPL completed two significant acquisitions that have reduced PPL's overall business risk profile and reapportioned the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business:

·On April 1, 2011, PPL, through an indirect, wholly owned subsidiary, PPL WEM, completed its acquisition of all the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently renamed WPD Midlands), from subsidiaries of E.ON AG.  WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England.

·On November 1, 2010, PPL acquired all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG.  Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC (LKE).  LKE is engaged in regulated utility operations through its subsidiaries, LG&E and KU.

See Note 106 to the Financial Statements for additional information on both acquisitions.the spinoff and acquisition.

Each rate-regulated business plansTalen Energy seeks to make materialoptimize the value from its competitive power generation assets and marketing portfolio while mitigating near-term volatility in both cash flow and earnings metrics. Talen Energy endeavors to accomplish this by matching projected output from its generation assets with forward power sales in the wholesale and retail markets while effectively managing exposure to fuel price volatility, counterparty credit risk and operational risk. Talen Energy is focused on safe, reliable, and resilient operations, disciplined capital investments overinvestment, portfolio optimization, cost management and the next several years to improve infrastructure and customer reliability.  See "Item 7. Management's Discussion and Analysispursuit of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources" for information on each Registrant's capital expenditure projections.value-enhancing growth opportunities.

ATo manage financing costs and access to credit markets, and to fund capital expenditures and growth opportunities, a key objective of PPL's business strategyTalen Energy is to maintain adequate liquidity capacity. In addition, Talen Energy has a strongfinancial risk management policy and operational procedures that, among other things, are designed to monitor and manage exposure to earnings and cash flow volatility related to, as applicable, changes in energy and fuel prices, interest rates, counterparty credit profile.  PPL's recent growth in rate-regulated businesses has provided the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that further enables PPL to support targeted credit profiles cost effectively across all of PPL's rated companies.  As a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing byquality and the operating companies,performance of generating units. To manage these risks, Talen Energy generally uses contracts such as appropriate.forwards, options, swaps and insurance contracts primarily focused on mitigating cash flow volatility within the next 12 month period.

AtThe following chart illustrates Talen Energy's organizational structure as of December 31, 2012, PPL had:2015.
Talen Energy's subsidiaries, Talen Generation, Raven, Jade, Sapphire, and MACH Gen, own and operate competitive power generation facilities. Another Talen Energy subsidiary, Talen Energy Marketing, markets the output of Talen Energy's plants, electricity, capacity and ancillary services, and other energy-related products in competitive wholesale and retail markets.


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Talen Energy Marketing sells the output of its affiliated generation facilities to a diverse group of wholesale customers, including RTOs and ISOs, utilities, cooperatives, municipalities, power marketers, and financial counterparties. Talen Energy Marketing also sells the output of its affiliated generation plants to commercial, industrial and residential retail customers.
Talen Energy earns revenue primarily by participating in energy and capacity markets and by providing related ancillary services.
The energy markets in which Talen Energy participates are designed to meet the short-term needs for electricity. They include day-ahead markets, where hourly prices are calculated for the next operating day based on bids and offers, and real-time spot markets, in which energy is continuously bought and sold based on actual grid operating conditions.

·$12.3 billion in operating revenues for the year (56% from regulated businesses),
The capacity markets in which Talen Energy participates are designed to procure sufficient generating capacity to meet forecasted peak demand to ensure that the longer-term needs for electricity are met to keep the applicable power grids operating reliably. PJM and ISO-NE procure capacity three years in advance whereas NYISO conducts three nearer term auctions; a six-month summer and winter strip auction, a monthly auction and a spot auction. Capacity markets provide generation owners, such as Talen Energy, some forward-looking revenue visibility.

Ancillary services, such as non-spinning reserves, responsive reserves and regulation up/down, are supplied in some of the markets in which Talen Energy operates to help maintain system reliability by compensating generators for being available during short-term capacity shortage conditions.

Talen Energy's generation fleet is diverse in terms of fuel, technology, dispatch characteristics and location. A majority of Talen Energy's revenue comes from the sale of electricity produced by its generation facilities. Talen Energy also produces additional revenue from the sale of capacity within the PJM, ISO-NE and NYISO markets as well as by providing ancillary services.

The charts below illustrate the composition and diversity of Talen Energy's generation portfolio capacity (summer rating) by market and fuel type as of December 31, 2015:
The charts above do not reflect the completed or announced divestitures of approximately 1,400 MW of generation capacity to satisfy the FERC approved mitigation in connection with the RJS Power acquisition. See "Acquisitions and Divestitures" below and Notes 1 and 6 to the Financial Statements for additional information.

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MARKETS

Included in the table below are the markets in which Talen Energy operates and the revenue opportunities presented by each:
·10.5 million end-users of its utility services,
·approximately 19,000 MW of generation (44% within regulated businesses), and
·approximately 18,000 full-time employees.

PPL's principal subsidiaries at December 31, 2012 are shown below (* denotes an SEC registrant).
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PPL Corporation*
      Revenue Opportunities
Markets Category Location Energy
Market		 Capacity
Market		 Ancillary
Services
PJM RTO All or part of thirteen states in the Northeast U.S. and the District of Columbia (DE, IL, IN, KY, MD, MI, NC, NJ, OH, PA, TN, VA & WV) X X X
ERCOT ISO Majority of the State of Texas X - X
NYISO ISO State of New York X PPL Capital FundingX X
ISO-NE RTO 
New England states (CT, MA, ME, NH, RI & VT) 
X X X
WECC (a) Investor Owned Utilities 14 States in the Western U.S., 2 Canadian provinces and northern Baja Mexico (AZ, CA, CO, ID, MT, NE, NM, NV, OR, SD, portion of TX, UT, WA & WY) X - 
LKE*
PPL Global
● Engages in the regulated distribution of electricity in the U.K.
PPL Electric*
● Engages in the regulated transmission and distribution of electricity in Pennsylvania
PPL Energy Supply*
LG&E*
● Engages in the regulated generation, transmission, distribution and sale of electricity in Kentucky, and distribution and sale of natural gas in Kentucky
KU*
● Engages in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky
PPL EnergyPlus
● Performs energy marketing and trading activities
● Purchases fuel
PPL Generation
● Engages in the competitive generation of electricity, primarily in Pennsylvania and Montana
Kentucky Regulated
Segment
U.K. Regulated
Segment
Pennsylvania Regulated Segment
Supply
Segment
X

In addition to PPL Corporation, the other SEC registrants included in this filing are:
(a)
Members are uniquely structured in that they typically do not have organized markets, but rather, are organized into 38 separate Balancing Authorities (BAs). Each BA is responsible for balancing loads and resources within their respective boundaries.

LG&E and KU Energy LLC, headquartered in Louisville, Kentucky, is a holding company with regulated utility operations through subsidiaries, LG&E and KU, and is a subsidiary of PPL.  LKE, formed in 2003, is the successor to a Kentucky entity incorporated in 1989.See "Item 2. Properties" for additional information on Talen Energy's generating plants, including each plants' market location.

Recent Market Developments

PJM

Louisville GasAs a result of unusual market and Electric Company, headquartered in Louisville, Kentucky, is a regulated utility engagedweather volatility in the first quarter of 2014, PJM determined that changes were necessary to ensure system reliability. In December 2014, PJM proposed to add an enhanced Capacity Performance (CP) product to the capacity market structure to permit additional compensation for generation transmission, distributionowners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirements, with higher penalties for non-performers. For more information on recent PJM market developments, see "Item 7. Combined Management's Discussion and saleAnalysis of electricityFinancial Condition and Results of Operations" for additional information.
ERCOT

The PUCT and ERCOT have taken significant measures to improve scarcity pricing in ERCOT.  ERCOT's system-wide offer cap was increased from $7,000 per MWh to $9,000 per MWh effective June 1, 2015.  An operating reserve demand curve (ORDC) was implemented in June 2014, which is intended to produce longer periods of gradually increasing scarcity prices, and the distributionPUCT and saleERCOT are currently evaluating whether any changes need to be made to improve the operation of natural gas in Kentucky.  LG&E was incorporated in Kentucky in 1913.  At December 31, 2012, LG&E owned 3,354 MW of electric power generation capacity and is implementing capital projects at an existing generation facility to provide 141 MW of additional generating capacity by the end of 2015.  LG&E also anticipates retiring 563 MW of coal-fired generating capacity by the end of 2015 to meet certain environmental regulations.  LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.ORDC during scarcity conditions.

Kentucky Utilities Company, headquartered in Lexington, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electricity in Kentucky, Virginia and Tennessee.  KU was incorporated in Kentucky in 1912 and Virginia in 1991.  KU serves its Virginia customers under the Old Dominion Power name while its Kentucky and Tennessee customers are served under the KU name.  At December 31, 2012, KU owned 4,833 MW of electric power generation capacity and is implementing capital projects at an existing generation facility owned by LG&E to provide 499 MW of additional generating capacity by the end of 2015.  KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.  KU also anticipates retiring 163 MW of coal-fired generating capacity by the end of 2015 to meet certain environmental regulations.  KU and LG&E jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.NYISO

PPL Electric Utilities Corporation, headquarteredThe NYISO will be undertaking its triennial Demand Curve Reset (DCR) process, which will reset the capacity auction parameters, potentially impacting compensation to capacity resources. Draft tariff sheets reflecting recommended changes to the DCR process are to be presented to the NYISO's Installed Capacity Working Group in Allentown, Pennsylvania, is a direct subsidiary of PPL incorporated in Pennsylvania in 1920 and a regulated public utility.  PPL Electric delivers electricity in its Pennsylvania service territory and provides electricity supply to retail customers in that territory as a PLR under the Customer Choice Act.February 2016.
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PPLTwo major initiatives, Reform the Energy Supply, LLC, headquarteredVision and the Clean Energy Standard are being pursued in Allentown, Pennsylvania,New York State. Both of these initiatives are long term endeavors and either or both could have impacts on the overall New York energy market. Talen Energy is an indirect subsidiary of PPL formed in 2000still assessing any potential impacts to both the market and is an energy company engaged through its subsidiaries in the generation and marketing of electricity, primarily in the northeastern and northwestern power markets of the U.S.  PPL Energy Supply's major operating subsidiaries are PPL EnergyPlus and PPL Generation.  In January 2011, PPL Energy Supply distributed its entire membership interest in PPL Global to its parent, PPL Energy Funding (the parent holding company of PPL Energy Supply and PPL Global with no other material operations), to better align PPL's organizational structure with the manner in which it manages these businesses and reports segment information in its consolidated financial statements.  The distribution separated the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business.  See Note 9 to the Financial Statements for additional information.  The 2010 operating results of PPL Global, which represented the U.K. Regulated segment (formerly International Regulated), are classified as discontinued operations.  At December 31, 2012, PPL Energy Supply owned or controlled 10,591 MW of electric power generation capacity and is implementing capital projects at certain of its existing generation facilities in Pennsylvania and Montana to provide 153 MW of additional generating capacity by the end of 2013.portfolio.

PPL's utility subsidiaries,ISO-NE

ISO-NE added an enhanced Performance Incentive (PI) product to the capacity market structure to permit additional compensation for generation owners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirement, with higher penalties for non-performers without exception. The PI product was first implemented in the ninth forward capacity auction for delivery year 2018/19, which was held in February 2015. ISO-NE merged the Northeast Massachusetts zone with the Southeastern Massachusetts/Rhode Island capacity zone to create the import-constrained Southern New England (SENE) zone. The tenth forward capacity auction will now only consist of two zones: SENE and toRest of Pool (including Maine, Western/Central Massachusetts, New Hampshire and Vermont). In addition,

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ISO-NE has unveiled a lesser extent, certain competitive supply subsidiaries, are subject to extensive regulation bynew, sloped demand curve design that could be implemented for the FERC related to wholesale power saleseleventh forward capacity auction and related transactions, electricity transmission service, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties and payments of dividends.  PPL and LKE are subject to certain FERC regulations as holding companies under PUHCA and the Federal Power Act, including with respect to accounting and record-keeping, inter-system sales of non-power goods and services and acquisitions of securities in, or mergers with, certain types of electric utility companies.would likely put downward pressure on clearing prices.

RESERVE MARGINS

SuccessorReserve margin is a measure of generation capacity available to meet peak demand. Each ISO/RTO sets a target reserve margin to ensure grid reliability, which is used as an indicator of a supply surplus or deficit based on the requirement. If the actual reserve margin exceeds the requirement, the system is in a surplus and Predecessor Financial Presentation(LKE, LG&Eenergy prices should remain lower and KU)stable. A deficit to the required reserve margin could trigger energy price spikes and volatility, sending a signal to the market that more capacity is needed. PJM, NYISO, and ISO-NE have forward looking capacity markets to procure sufficient capacity to meet forecasted demand. ERCOT operates in an energy only market, where scarcity pricing sends the signal to develop more capacity. Each market is currently well supplied and reserve margins exceed their targets and low energy prices are reflective of the adequate reserves. The table below contains the target reserve margin and the expected reserve margin for the 2015/16 planning year for each of the aforementioned ISOs/RTOs:
ISO/RTO Target Reserve Margin (a) 2015/16 Planning Year Reserve Margin (a)
PJM (b) 15.6% 20.2%
NYISO 17.0% 24.7%
ISO-NE 15.0% 22.8%
ERCOT 13.8% 15.7%

(a)
Source: data obtained from applicable ISO/RTO or other federal agency publications.
(b)
PJM announced that the target reserve margin increased to 16.5% for planning year 2019/20.

OPERATIONS

LKE's, LG&E's and KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor.  Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting.  Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE, LG&E and KU have not changed as a result of the acquisition.Revenues by Segment

Segment Information

(PPL)

PPLTalen Energy is organized into four reportablein two segments: Kentucky Regulated, U.K. Regulated (name changed in 2012 from International Regulated), Pennsylvania RegulatedEast and Supply.  There were no changes to reportable segments in 2012 other thanWest, based on geographic location. The East segment includes the name change noted above.

A comparison of PPL's three regulated segments is shown below:
           
   KY Regulated (a) U.K. Regulated (b) PA Regulated (c)
           
For the year ended December 31, 2012:         
 Operating Revenues (in billions) $2.8 $2.3 $1.8
 Net Income Attributable to PPL Shareowners (in millions) $177 $803 $132
 Electric energy delivered (GWh) 30,908  77,467  36,023 
At December 31, 2012:        
 Regulatory Asset Base (in billions) (d) $6.7 $8.6 $3.5
 Service area (in square miles) 9,400  21,400  10,000 
 End-users (in millions) 1.3  7.8  1.4 

(a)Business activities include the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas.
(b)Business activities include the distribution of electricity.
(c)Business activities include the transmission and distribution of electricity.
(d)Represents RAV for U.K. Regulated, capitalization for KY Regulated and rate base for PA Regulated.
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(PPL Energy Supply)

PPL Energy Supply has operated in a single reportable segment since 2011.  Prior to 2011, PPL Energy Supply's segments consisted of Supply and U.K. Regulated (formerly International Regulated).  In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding, to better align PPL's organizational structure with the manner in which it manages its businesses and reports segment information in its consolidated financial statements.  The distribution separated the U.S.-based competitive energygenerating, marketing and supply business fromtrading activities in PJM, NYISO and ISO-NE. The West segment includes the U.K.-based regulated electricity distribution business.  The 2010 operating results of PPL Global, which represented the U.K. Regulated segment, are classified as discontinued operations for PPL Energy Supply.

(PPL Electric, LKE, LG&Egenerating, marketing and KU)

PPL Electric, LKE, LG&Etrading activities located in ERCOT and KU each operate within a single reportable segment.

(PPL)

WECC. See Note 2 to the Financial Statements for financial information about the segments.

·
Kentucky Regulated Segment (PPL)
Consists of the operations of LKE, which owns and operates regulated public utilities engaged in the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas, representing primarily the activities of LG&E and KU.  The Kentucky Regulated segment also includes interest expense related to the 2010 Equity Units that were issued to partially finance the acquisition of LKE.

(PPL, LKE, LG&E and KU)

LKE became a wholly owned subsidiary of PPL on November 1, 2010.  LG&E and KU are engaged in the regulated generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, Virginia and Tennessee.  LG&E also engages in the distribution and sale of natural gas in Kentucky.  LG&E provides electric service to approximately 393,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in 9 counties.  LG&E provides natural gas service to approximately 318,000 customers in its electric service area and 7 additional counties in Kentucky.  KU provides electric service to approximately 510,000 customers in 77 counties in central, southeastern and western Kentucky; approximately 29,000 customers in 5 counties in southwestern Virginia; and fewer than 10 customers in Tennessee, covering approximately 4,800 non-contiguous square miles.  KU also sells wholesale electricity to 12 municipalities in Kentucky under load following contracts.  In Virginia, KU operates under the name Old Dominion Power Company.

Acquisition by PPL

In September 2010, the KPSC approved a settlement agreement among PPL and all of the intervening parties to PPL's joint application to the KPSC for approval of its acquisition of ownership and control of LKE.  In the settlement agreement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013.  Under the terms of the settlement, LG&E and KU retained the right to seek approval for the deferral of "extraordinary and uncontrollable costs."  Interim rate adjustments continued to be permissible during that period through existing fuel, environmental and demand side management recovery mechanisms.  In October 2010, both the VSCC and the TRA approved the transfer of control of LKE to PPL.  The orders and the settlement agreement approved by the KPSC contained certain other commitments by LG&E and KU with regard to operations, workforce, community involvement and other matters.

Also in October 2010, the FERC approved the application for the transfer of control of the utilities.  The approval included various conditional commitments, such as a continuation of certain existing undertakings with intervenors in prior cases, an agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that LG&E and KU have agreed not to seek recovery of the same transaction-related costs from retail customers and agreements to coordinate with intervenors in certain pending matters.

See Note 10 to the Financial Statements for additional information on regulatory matters related toTalen Energy's segments and the acquisition.

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Franchises and Licenses
segment reevaluation.

LG&E and KU provide electricity delivery service, and LG&E provides natural gas distribution service, in their respective service territories pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by state legislatures, cities or municipalities or other entities. 

Competition

There are currently no other electric public utilities operating within the electric service areas of LKE.  From time to time, bills are introduced into the Kentucky General Assembly which seek to authorize, promote or mandate increased distributed generation, customer choice or other developments.  Neither the Kentucky General Assembly nor the KPSC has adopted or approved a plan or timetable for retail electric industry competition in Kentucky.  The nature or timing of any legislative or regulatory actions regarding industry restructuring and their impact on LKE, which may be significant, cannot currently be predicted.  Virginia, formerly a deregulated jurisdiction, has enacted legislation that implemented a hybrid model of cost-based regulation.  KU's operations in Virginia have been and remain regulated.

Alternative energy sources such as electricity, oil, propane and other fuels provide indirect competition for natural gas revenues of LKE.  Marketers may also compete to sell natural gas to certain large end-users.  LG&E's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity; therefore, customer natural gas purchases from alternative suppliers do not generally impact profitability.  However, some large industrial and commercial customers may physically bypass LG&E's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.

Operating Revenues

Details of operating revenues by customer class are shown below.
                          
  Successor  Predecessor
  Year Ended Year Ended Two Months Ended  Ten Months Ended
  December 31, 2012 December 31, 2011 December 31, 2010  October 31, 2010
     % of    % of    % of     % of
  Revenue Revenue Revenue Revenue Revenue Revenue  Revenue Revenue
LKE (a)                         
Commercial $ 723    26  $ 719    26  $ 123    25   $ 573    26 
Industrial   551    20    533    19    86    17     424    19 
Residential   1,071    39    1,087    39    219    44     886    40 
Retail - other   270    10    269    9    43    9     212    10 
Wholesale - municipal   102    4    104    4    15    3     88    4 
Wholesale - other (b)   42    1    81    3    8    2     31    1 
Total $ 2,759    100  $ 2,793    100  $ 494    100   $ 2,214    100 
                          
LG&E                         
Commercial $ 374    28  $ 372    27  $ 66    26   $ 287    27 
Industrial   170    13    152    11    26    10     122    12 
Residential   548    41    561    41    113    44     446    42 
Retail - other   131    10    130    10    22    9     98    9 
Wholesale - other (b) (c)   101    8    149    11    27    11     104    10 
Total $ 1,324    100  $ 1,364    100  $ 254    100   $ 1,057    100 
                          
KU                         
Commercial $ 349    23  $ 347    22  $ 57    22   $ 286    23 
Industrial   381    25    381    25    60    23     302    24 
Residential   523    34    526    34    106    40     440    35 
Retail - other   139    9    139    9    21    8     114    9 
Wholesale - municipal   102    7    104    7    15    6     88    7 
Wholesale - other (b) (c)   30    2    51    3    4    1     18    2 
Total $ 1,524    100  $ 1,548    100  $ 263    100   $ 1,248    100 

(a)The LKE Successor information also represents PPL's Kentucky Regulated segment.
(b)Includes wholesale and transmission revenues.
(c)Includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE.

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Power Supply

At December 31, 2012, LKE owned, controlled or had an ownership interest in generating capacity (summer rating) of 8,187 MW, of which 3,354 MW related to LG&E and 4,833 MW related to KU, in Kentucky, Indiana, and Ohio.  See "Item 2. Properties - Kentucky Regulated Segment" for a complete list of LKE's generating facilities.

The system capacity of LKE's owned or controlled generation is based upon a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changes in circumstances.

During 2012, LKE's Kentucky power plants generated the following amounts of electricity.

 Thousands of MWh
Fuel SourceLKE LG&E KU
Coal (a) 32,820   15,051   17,769 
Oil / Gas 1,340   463   877 
Hydro 250   212   38 
Total (b) 34,410   15,726   18,684 

(a)Includes 990 MWh of power generated by and purchased from OVEC for LKE, 685 MWh for LG&E and 305 MWh for KU.
(b)This generation represents a 4% decrease for LKE, a 4% decrease for LG&E and a 3% decrease for KU from 2011 output.

A significant portion of LG&E's and KU's generated electricity was used to supply its retail and municipal customer base.

LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.  When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E.  When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU.

See "Item 2. Properties - Kentucky Regulated Segment" for additional information regarding LG&E's and KU's plans for development of Cane Run Unit 7.  KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.  LG&E and KU also anticipate retiring 563 MW and 163 MW of coal-fired generating capacity by the end of 2015 to meet certain environmental regulations.

Fuel Supply

Coal is expected to be the predominant fuel used by LG&E and KU for baseload generation for the foreseeable future.  However, natural gas will play a more significant role starting in 2015 when Cane Run Unit 7 is expected to be placed into operation.  This unit is expected to be used for baseload generation.  Natural gas and oil will continue to be used for intermediate and peaking capacity and flame stabilization in coal-fired boilers.

Fuel inventory is maintained at levels estimated to be necessary to avoid operational disruptions at coal-fired generating units.  Reliability of coal deliveries can be affected from time to time by a number of factors including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties.  To enhance the reliability of natural gas supply, LG&E and KU have secured long-term pipeline capacity on the interstate pipeline serving the new combined cycle unit and six simple cycle combustion turbine units.

LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2017 and normally augment their coal supply agreements with spot market purchases, as needed.

For their existing units, LG&E and KU expect for the foreseeable future to purchase most of their coal from western Kentucky, southern Indiana, southern Illinois and Ohio.  The use of high sulfur coal increased during 2012 due to the installation of scrubbers and the sulfuric acid mist mitigation system at KU's E.W. Brown plant.  In 2013 and beyond, LG&E and KU may purchase certain quantities of ultra-low sulfur content coal from Wyoming for blending at TC2.  Coal is delivered to the generating plants by barge, truck and rail.

8
(PPL, LKE and LG&E)

Natural Gas Supply

Five underground natural gas storage fields, with a current working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to LG&E's firm sales customers.  By using natural gas storage facilities, LG&E avoids the costs typically associated with more expensive pipeline transportation capacity to serve peak winter heating loads.  Natural gas is stored during the summer season for withdrawal during the following winter heating season.  Without this storage capacity, LG&E would be required to purchase additional natural gas and pipeline transportation services during winter months when customer demand increases and the prices for natural gas supply and transportation services are typically at their highest.  Several suppliers under contracts of varying duration provide competitively priced natural gas.  At December 31, 2012, LG&E had a 12 Bcf inventory balance of natural gas stored underground with a carrying value of $42 million.

LG&E has a portfolio of supply arrangements of varying terms with a number of suppliers designed to meet its firm sales obligations.  These natural gas supply arrangements include pricing provisions that are market-responsive.  In tandem with pipeline transportation services, these natural gas supplies provide the reliability and flexibility necessary to serve LG&E's natural gas customers.

LG&E purchases natural gas supply transportation services from two pipelines.  LG&E has contracts with one pipeline that are subject to termination by LG&E between 2015 and 2018.  Total winter capacity under these contracts is 194,900 MMBtu/day and summer capacity is 88,000 MMBtu/day.  LG&E has a contract with another pipeline that expires in October 2014.  Total winter and summer capacity under this contract is 20,000 MMBtu/day during both seasons.

(PPL, LKE, LG&E and KU)

Rates and Regulation

LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the FERC, the VSCC and the TRA.  LG&E and KU operate under a FERC-approved open access transmission tariff.  LG&E and KU contract with the Tennessee Valley Authority to act as their transmission reliability coordinator.  LG&E and KU contracted with Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements under a contract that expired on August 31, 2012.  After receiving FERC approval, LG&E and KU transferred from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012.

In February 2013, LG&E and KU submitted a compliance filing to the FERC reflecting their participation with other utilities in the Southeastern Regional Transmission Planning relating to certain FERC Order 1000 requirements.  FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electric transmission planning activities. 

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms.  As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.

KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions).  All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.

KU's rates to municipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions).  All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.

See Note 6 to the Financial Statements for additional information on cost recovery mechanisms.
9
2012 Kentucky Rate Case

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E.  In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement.  Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E.  The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU.  The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%.  On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement.  The new rates became effective on January 1, 2013.  In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

FERC Wholesale Rates

In May 2012, KU submitted to the FERC the annual adjustments to the formula rate which incorporated certain proposed increases.  These rates became effective as of July 1, 2012.

·
U.K. Regulated Segment (PPL)
Includes WPD, a regulated electricity distribution business in the U.K.

WPD, through indirect wholly owned subsidiaries, operates four of the 15 regulated distribution networks providing electricity service in the U.K.  With the April 2011 acquisition of WPD Midlands, the number of end-users served has more than doubled totaling 7.8 million across 21,400 square miles in Wales, southwest and central England.  See Note 10 to the Financial Statements for additional information on the acquisition.

Details of revenue by categorysegment for the years ended December 31 as adjusted to reflect the November 2015 segment reevaluation referenced above, are shown below.as follows:
 2015 2014 2013
 East West Total East West Total East West Total
Energy                 
Wholesale energy (a)$2,631
 $211
 $2,842
 $2,609
 $128
 $2,737
 $2,846
 $95
 $2,941
Retail energy1,022
 73
 1,095
 1,162
 81
 1,243
 945
 82
 1,027
Total Energy3,653
 284
 3,937
 3,771
 209
 3,980
 3,791
 177
 3,968
Energy-related businesses (b)544
 —
 544
 601
 —
 601
 527
 —
 527
Total$4,197
 $284
 $4,481
 $4,372
 $209
 $4,581
 $4,318
 $177
 $4,495

  2012  2011  2010 
  Revenue % of Revenue Revenue % of Revenue Revenue % of Revenue
Utility revenues (a) $2,289   98  $1,618   98  $727   96 
Energy-related businesses  47   2   35   2   34   4 
Total $ 2,336    100  $ 1,653   100  $ 761    100 

(a)The above years are not comparable as WPD Midlands was acquired in April 2011.  2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag.

WPD's energy-related businesses revenues include ancillary activities that support the distribution business, including telecommunications and real estate.  WPD's telecommunication revenues are from the rental of fiber optic cables primarily attached to WPD's overhead electricity distribution network.  WPD also provides meter services to businesses across the U.K.

Franchise and Licenses

WPD is authorized by Ofgem to provide electric distribution services within its concession areas and service territories, subject to certain conditions and obligations.  For instance, WPD is subject to Ofgem regulation of the regulated revenue it can earn and the quality of service it must provide, and WPD can be fined or have its licenses revoked if it does not meet the mandated standard of service.

Competition

Although WPD operates in non-exclusive concession areas in the U.K., it currently faces little competition with respect to end-users connected to its network.  WPD's four distribution businesses, WPD (South West), WPD (South Wales), WPD (West Midlands) and WPD (East Midlands), are thus regulated monopolies which operate under regulatory price controls.

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Revenue and Regulation

The operations of WPD (South West), WPD (South Wales), WPD (East Midlands) and WPD (West Midlands) are regulated by Ofgem under the direction of the Gas and Electricity Markets Authority.  The Electricity Act 1989 provides the fundamental legal framework of electricity companies and established licenses that required each of the DNOs to develop, maintain and operate efficient distribution networks.  Ofgem has established a price control mechanism that restricts the amount of revenue that can be earned by regulated business and provides for an increase or reduction in revenues based on incentives or penalties for exceeding or underperforming against pre-established targets.

This regulatory structure is an incentive-based regulatory structure in comparison to the U.S. utility businesses which operate under a cost-based regulatory framework.  Under the UK regulatory structure, electricity distribution revenues are currently set every five years, but extending to eight years in the next price control period beginning in April 2015.  The revenue that DNOs can earn in each of the five years is the sum of:  i) the regulator's view of efficient operating costs, ii) a return on the capital from the RAV plus an annual adjustment for the inflation determined by Retail Price Index (RPI) for the prior calendar year, iii) a return of capital from the RAV (i.e. depreciation), and iv) certain pass-through costs over which the DNO has no control.  Additionally, incentives are provided for a range of activities including exceeding certain reliability and customer service targets.

WPD is currently operating under DPCR5 which was completed in December 2009 and is effective for the period from April 1, 2010 through March 31, 2015.  Ofgem allowed WPD (South West) and WPD (South Wales) an average increase in total revenues, before inflationary adjustments, of 6.9% in each of the five years and WPD Midlands an average increase in total revenues, before inflationary adjustments, of 4.5% in each of the five years.  The revenue increase includes reimbursement for higher operating and capital costs to be incurred driven by additional requirements.  In DPCR5, Ofgem decoupled WPD's allowed revenue from volume delivered over the five-year price control period.  However, in any fiscal period WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the allowed revenue for a given period.  Under recoveries are recovered in the next regulatory year, however, PPL does not record a receivable for under recoveries in the current period.  Over recoveries are reflected in the current period as a liability and are not included in revenue.

In addition to providing a base regulated revenue allowance, Ofgem has established incentive mechanisms to provide significant opportunities to enhance overall returns by improving network efficiency, reliability and customer service.  Some of the more significant incentive mechanisms under DPCR5 include:

·Interruptions Incentive Scheme (IIS) - This incentive has two major components: 1)  Customer interruptions and 2) Customer minutes lost and is designed to incentivize the DNOs to invest and operate their networks to manage and reduce both the frequency and duration of power outages experienced by customers.  The target for each DNO is based on a benchmark of data from the last four years of the prior price control period.

Effective April 1, 2012, an additional customer satisfaction incentive mechanism was implemented that includes a customer satisfaction survey, a complaints metric and a measure of stakeholder engagement.  This incentive replaced the customer response telephone performance incentive that was effective April 1, 2010.

·Line Loss Incentive - This incentive existed in the prior price control review, DPCR4, and was designed to incentivize DNOs to invest in lower loss equipment, to change the way they operate their systems to reduce losses, and to detect theft and unregistered meters.  In November 2012, Ofgem issued a decision not to activate the DPCR5 line loss incentive.  See Note 6 to the Financial Statements for information on Ofgem's review of line loss calculations.

·Information Quality Incentive (IQI) - The IQI is designed to incentivize the DNOs to provide good quality information when they submit their business plans to Ofgem during the price control process and to execute the plan they submitted.  The IQI eliminates the distinction between capital expenditure and operating expense and instead looks at total expenditure.  Total expenditure is allocated 85% to "slow pot" which is added to RAV and recovered over 20 years through the regulatory depreciation of the RAV and 15% to "fast pot" which is recovered during the current price control review period.  The IQI then provides for incentives or penalties at the end of DPCR5 based on the ratio of actual expenditures to the expenditures submitted to Ofgem that were the basis for the revenues allowed during the five-year price control review period.
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At the beginning of DPCR5, WPD was awarded $301 million in incentive revenue of which $222 million will be included in revenue throughout the current price control period with the balance recovered over subsequent price control periods.  Since the beginning of DPCR5, WPD earned additional incentive revenue, primarily from IIS of $83 million and $30 million for the regulatory years ended March 31, 2012 and 2011, which will be included in revenue for the 2013-14 and 2012-13 regulatory years.

In October 2010, Ofgem announced a new pricing model that will be effective for the U.K. electricity distribution sector, including WPD, beginning April 2015.  The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure.  The next electricity distribution price control review is referred to as RIIO-ED1.  In September 2012, Ofgem published a strategy consultation document providing an overview of its approach for RIIO-ED1 and is expected to publish a policy decision document in February 2013.  Key components of the RIIO-ED1 are: an extension of the price review period to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital.  Ofgem has also indicated that the depreciation of the RAV for RAV additions after April 1, 2015 will change from 20 years to 45 years.  Management is in the process of creating the "well-justified business plans" required by Ofgem for WPD's four DNOs.  These plans are expected to be submitted to Ofgem in July 2013 as part of the RIIO-ED1 review process.  Once the business plans are complete, management will be in a better position to determine the effect of RIIO-ED1 on future financial results.  See "Item 1A. Risk Factors - Risks Related to U.K. Regulated Segment."

Customers

The majority of WPD's revenue is known as DUoS and is derived from charging energy suppliers for the delivery of electricity to end-users and thus its customers are the suppliers to those end-users.  Ofgem requires that all licensed electricity distributors and suppliers become parties to the Distribution Connection and Use of System Agreement.  This agreement sets out how creditworthiness will be determined and, as a result, whether the supplier needs to provide collateral.

·
Pennsylvania Regulated Segment (PPL)
Includes the regulated electric delivery operations of PPL Electric.

(PPL and PPL Electric)

PPL Electric is subject to regulation as a public utility by the PUC, and certain of its transmission activities are subject to the jurisdiction of the FERC under the Federal Power Act.  PPL Electric delivers electricity to approximately 1.4 million customers in a 10,000-square mile territory in 29 counties of eastern and central Pennsylvania.  PPL Electric also provides electricity supply in this territory as a PLR.

Details of electric revenues by customer class for the years ended December 31, are shown below.

  2012  2011  2010 
  Revenue % of Revenue Revenue % of Revenue Revenue % of Revenue
                   
Residential $ 1,108    63  $ 1,266    67  $ 1,469    60 
Industrial   53    3    62    3    123    5 
Commercial   366    21    431    23    588    24 
Other (a) (b)   236    13    133   7    275   11 
Total $ 1,763    100  $ 1,892    100  $ 2,455    100 

(a)Includes regulatory over- or under-recovery reconciliation mechanisms, pole attachment revenues, street lighting and net transmission revenues.
(b)Included in these amounts for 2012, 2011 and 2010 are $3 million, $11 million and $7 million of retail and wholesale electric to affiliate revenue which is eliminated in consolidation for PPL.

Franchise, Licenses and Other Regulations

PPL Electric is authorized to provide electric public utility service throughout its service area as a result of grants by the Commonwealth of Pennsylvania in corporate charters to PPL Electric and companies to which it has succeeded and as a result of certification by the PUC.  PPL Electric is granted the right to enter the streets and highways by the Commonwealth subject to certain conditions.  In general, such conditions have been met by ordinance, resolution, permit, acquiescence or other action by an appropriate local political subdivision or agency of the Commonwealth.

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Competition

Pursuant to authorizations from the Commonwealth of Pennsylvania and the PUC, PPL Electric operates a regulated distribution monopoly in its service area.  Accordingly, PPL Electric does not face competition in its electric distribution business.

The PPL Electric transmission business, operating under the purview of the FERC-approved PJM Open Access Transmission Tariff, is subject to competition from entities that are not incumbent PJM transmission owners with respect to building and ownership of transmission facilities within PJM.  No authority has yet been promulgated that sets forth the parameters of non-incumbent competition.

Rates and Regulation

Transmission and Distribution

PPL Electric's transmission facilities are within PJM, which operates the electric transmission network and electric energy market in the Mid-Atlantic and Midwest regions of the U.S.

PJM serves as a FERC-approved RTO to promote greater participation and competition in the region it serves.  In addition to operating the electric transmission network, PJM also administers regional markets for energy, capacity and ancillary services.  A primary objective of any RTO is to separate the operation of, and access to, the transmission grid from market participants that buy or sell electricity in the same markets.  Electric utilities continue to own the transmission assets and to receive their share of transmission revenues, but the RTO directs the control and operation of the transmission facilities.

As a transmission owner, PPL Electric's transmission revenues are billed to PJM in accordance with a FERC tariff that allows recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update.  As a PLR, PPL Electric also purchases transmission services from PJM.  See "PLR" below.

In April 2010, the FERC issued an order concluding that under the PJM Open Access Transmission Tariff, PJM may, but is not required to, designate an entity other than the incumbent PJM transmission owner to own and construct economic expansion projects and receive cost-of-service based compensation for the use of its facilities.  Additionally, the FERC directed PJM to file tariff changes necessary for non-incumbent transmission owners to be provided opportunity to propose and construct transmission projects in accordance with exclusions specified in the April 2010 order and consistent with state and local laws and regulations.  PJM tariff changes are currently under review by the FERC.

PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions such as materials and supplies inventories and customer deposits and advances) plus certain operating expenses.  Operating expenses included in PPL Electric's distribution base rates include wages and benefits, other operation and maintenance expenses, depreciation, and taxes.

In November 2004, Pennsylvania enacted the AEPS, which requires electricity distribution companies and electricity generation suppliers to obtain a portion of the electricity sold to retail customers in Pennsylvania from alternative energy sources.  Under the default service procurement plans approved by the PUC, PPL Electric purchases all of the alternative energy generation supply it needs to comply with the AEPS.

Act 129 creates an energy efficiency and conservation program, a demand side management program, smart metering technology requirements, new PLR generation supply procurement rules, remedies for market misconduct, and changes to the existing AEPS.

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, a DSIC.  In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for implementation of Act 11.  Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC.  The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC.  PPL Electric filed its LTIIP in September 2012 and the PUC subsequently approved the LTIIP on January 10, 2013.  PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013 with rates proposed to be effective beginning May 1, 2013.

See "Regulatory Matters - Pennsylvania Activities" in Note 6 to the Financial Statements for additional information regarding Act 129, Act 11 and other legislative and regulatory impacts.

13

PLR

The Customer Choice Act requires Electric Distribution Companies (EDCs), including PPL Electric, to act as a PLR of electricity supply for customers who do not choose to shop for supply with a competitive supplier and provides that electricity supply costs will be recovered by the PLR pursuant to regulations established by the PUC.  As of December 31, 2012, the following percentages of PPL Electric's customer load were provided by competitive suppliers:  46% of residential, 84% of small commercial and industrial and 99% of large commercial and industrial customers.  The PUC continues to be interested in expanding the competitive market for electricity.  See "Regulatory Matters - Pennsylvania Activities" in Note 6 to the Financial Statements for additional information.

PPL Electric's cost of electricity generation is based on a competitive solicitation process.  The PUC approved PPL Electric's default service plan for the period January 2011 through May 2013, which includes 14 solicitations for electricity supply beginning January 1, 2011 with a portion extending beyond May 2013.  Pursuant to this plan, PPL Electric contracts for all of the electricity supply for residential, small commercial and small industrial customers, large commercial and large industrial customers who elect to take that service from PPL Electric.  These solicitations include a mix of spot market purchases and long-term and short-term purchases ranging from five months to ten years to fulfill PPL Electric's obligation to provide customer electricity supply as a PLR.  To date, PPL Electric has concluded all of its planned competitive solicitations under the plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015.  PPL Electric filed its plan in May 2012.  In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity supply from the competitive retail market.  In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.

Numerous alternative suppliers have offered to provide generation supply in PPL Electric's service territory.  Whether its customers purchase electricity supply from these alternative suppliers or from PPL Electric as a PLR, the purchase of such supply has no impact on the financial results of PPL Electric.  The costs to purchase PLR supply, including charges paid to PJM for related transmission services, are passed directly by PPL Electric to its PLR customers without markup.  See "Energy Purchase Commitments" in Note 15 to the Financial Statements for additional information regarding PPL Electric's solicitations.

Rate Cases

2012 Rate Case

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013.  On December 28, 2012, in its final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million.  The approved rates became effective January 1, 2013.

Also in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order.  PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.

See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for additional information on Hurricane Sandy.

FERC Formula Rates

Transmission rates are regulated by the FERC.  PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism.
PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates.  Each update has been subsequently challenged by a group of municipal customers.  In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order.  In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges.  Settlement conferences were held in late 2012 and early 2013.  In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that
14
challenge with the 2010 and 2011 challenges.  PPL Electric anticipates that there will be additional settlement conferences held in 2013.  PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization.  This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC.  At December 31, 2012 and December 31, 2011, $52 million and $53 million are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.

See Note 6 to the Financial Statements for additional information on rate mechanisms.

(PPL and PPL Energy Supply)

·Supply Segment
Owns and operates competitive domestic power plants to generate electricity; markets and trades this electricity, purchased power, and other energy-related products to competitive wholesale and retail markets; and acquires and develops competitive domestic generation projects.  Consists primarily of the activities of PPL Generation and PPL EnergyPlus.

PPL Energy Supply has generation assets that are located in the northeastern and northwestern U.S. markets.  The northeastern generating capacity is located primarily in Pennsylvania within PJM and northwestern generating capacity is located in Montana.  PPL Energy Supply enters into energy and energy-related contracts to hedge the variability of expected cash flows associated with its generating units and marketing activities, as well as for trading purposes.  PPL EnergyPlus sells the electricity produced by PPL Energy Supply's generation plants based on prevailing market rates.  PPL Energy Supply's total expected generation in 2013 is anticipated to be used to meet its committed contractual sales.  PPL Energy Supply has entered into commitments of varying quantities and terms for 2014 and beyond.

Details of revenue by category for the years ended December 31, are shown below.

   2012  2011  2010 
   Revenue % of Revenue Revenue % of Revenue Revenue % of Revenue
Energy                  
 Wholesale (a) $ 4,200    76  $ 5,240    82  $ 4,347    85 
 Retail   848    16    727    11    415    8 
 Trading   4       (2)      2    
 Total energy   5,052    92    5,965    93    4,764    93 
Energy-related businesses (b)   448    8    464    7    364    7 
Total $ 5,500    100  $ 6,429    100  $ 5,128    100 

(a)Included in these amounts for 2012, 2011,2015, 2014 and 20102013 are $78$14 million, $26$84 million and $320$51 million of wholesale electricity sales to ana former affiliate, PPL Electric, which are eliminated in consolidation for PPL.Electric.
(b)
Energy-related businesses are mechanical contracting and services subsidiaries that primarily support the generation and marketing and trading businesses in Talen Energy's East segment. Activities of PPL Energy Supply.  Their activitiesthese businesses include developing renewable energy projects and providing energy-related products and services to commercial and industrial customers through their mechanical contracting and services subsidiaries.  Energy-related businesses for PPL's Supply segment had additional revenues not related to PPL Energy Supply of $13 million, $8 million and $11 million for 2012, 2011 and 2010, which are not included in this table.
customers.



Power Supply
6

Power Generation by Fuel Source and physical condition of the units, and may be revised periodically to reflect changes in circumstances.  Generating capacity controlled by PPL Generation and other PPL Energy Supply subsidiaries includes power obtained through PPL EnergyPlus' power purchase agreements.  See "Item 2. Properties - Supply Segment" for a complete listing of PPL Energy Supply's generating capacity.Segment

During 2012, PPL2015, Talen Energy Supply owned or controlled power plants (including facilities for which Talen Energy has the rights to the output) that generated the following amounts of electricity.electricity (by segment):

15
 GWh
Fuel SourceEast West Total
Nuclear (a)18,505
 —
 18,505
Natural Gas/Oil15,320
 2,470
 17,790
Coal18,181
 3,775
 21,956
Hydro903
 —
 903
Renewables (b)293
 —
 293
Total53,202
 6,245
 59,447

   Thousands of MWhs
Fuel Source Northeastern Northwestern Total
        
Nuclear  15,224     15,224 
Oil / Gas  9,383     9,383 
Coal  16,857   3,232   20,089 
Hydro  552   3,443   3,995 
Renewables (a)  342     342 
Total  42,358   6,675   49,033 

(a)PPLRepresents Talen Energy's share of the total output.
(b)In 2015, Talen Energy Supply subsidiaries ownowned or controlcontrolled renewable energy projects (including facilities for which Talen Energy has the rights to the output) located in Pennsylvania, New Jersey, Vermont Connecticut and New Hampshire with aan aggregate generating capacity (summer rating) of 7026 MW. PPL EnergyPlus sellsTalen Energy Marketing sold the energy, capacity and RECs produced by these plants into the wholesale market as well as to commercial and industrial and institutional customers. In November 2015, projects that had an aggregate generating capacity of 19 MW were sold. For the projects sold, the above generation amounts include generation through their date of sale.

PPL Energy Supply's generation subsidiaries are EWGs that sell electricity into wholesale markets.  EWGs are subject to regulation by the FERC, which has authorized these EWGs to sell the electricity generated at market-based prices.  This electricity is sold to PPL EnergyPlus under FERC-jurisdictional power purchase agreements.  PPL Susquehanna is subject to the jurisdiction of the NRC in connection with the operation of the Susquehanna nuclear units.  Certain of PPL Energy Supply's other subsidiaries are subject to the jurisdiction of the NRC in connection with the operation of their fossil plants with respect to certain level and density monitoring devices.  Certain operations of PPL Generation's subsidiaries are also subject to OSHA and comparable state statutes.

See Note 9 to the Financial Statements for information on the 2011 sale of certain non-core generation facilities, the 2010 sale of the Long Island generation business and the 2010 completion of the sale of the Maine hydroelectric generation business.Fuel Supply

See "Item 2. Properties - Supply Segment"Properties" for additional information regarding PPL Generation's plans for capital projects in Pennsylvania and Montana that are expected to provide 153 MW of additional electric generating capacity by the end of 2013.

Fuel Supply

PPL EnergyPlus acts as agent for PPL Generation to procure and optimize its various fuels.

Coal

Pennsylvania

PPL EnergyPlus actively manages PPL Energy Supply's coal requirements by purchasing coal principally from mines located in northern Appalachia.

During 2012, PPL Generation purchased 5.6 million tons of coal required for its wholly owned Pennsylvania plants under short-term and long-term contracts.  The amount of coal in inventory varies from time to time depending on market conditions and plant operations.

PPL Generation, by and through its agent PPL EnergyPlus, has agreements in place that will provide more than 23 million tons of PPL Generation's projected coal needs for the Pennsylvania power plants from 2013 through 2018.

A PPL Generation subsidiary owns a 12.34% interest in the Keystone plant and a 16.25% interest in the Conemaugh plant.  PPL Generation owns a 12.34% interest in Keystone Fuels, LLC and a 16.25% interest in Conemaugh Fuels, LLC.  The Keystone plant contracts with Keystone Fuels, LLC for its coal requirements, which provided 4.3 million tons of coal to the Keystone plant in 2012.  The Conemaugh plant requirements are purchased under contract from Conemaugh Fuels, LLC, which provided 4.1 million tons of coal to the Conemaugh plant in 2012.

All PPL Generation coal plants within Pennsylvania are equipped with scrubbers, which use limestone in their operations.  Acting as agent for PPL Generation, PPL EnergyPlus has entered into contracts with limestone suppliers that will provide for those plants' limestone requirements through 2014.  During 2012, 382,000 tons of limestone were delivered to Brunner Island and Montour under these contracts.  Annual limestone requirements approximate 400,000-500,000 tons.
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Montana

PPL Montana has a 50% leasehold interest in Colstrip Units 1 and 2, and a 30% leasehold interest in Colstrip Unit 3.  NorthWestern owns a 30% interest in Colstrip Unit 4.  PPL Montana and NorthWestern have a sharing agreement that governs each party's responsibilities and rights relating to the operation of Colstrip Units 3 and 4.  Under the terms of that agreement, each party is responsible for 15% of the total non-coal operating and construction costs of Colstrip Units 3 and 4, regardless of whether a particular cost is specific to Colstrip Unit 3 or 4 and is entitled to take up to 15% of the available generation from Units 3 and 4.  Each party is responsible for its own coal costs.  PPL Montana, along with the other Colstrip owners, is party to contracts to purchase 100% of its coal requirements with defined coal quality characteristics and specifications.  PPL Montana, along with the other Colstrip Units 1 and 2 owner, has a long-term purchase and supply agreement with the current supplier for Units 1 and 2, which provides these units 100% of their coal requirements through December 2014, and at least 85% of such requirements from January 2015 through December 2019.  PPL Montana, along with the other Colstrip Units 3 and 4 owners, has a long-term coal supply contract for Units 3 and 4, which provides these units 100% of their coal requirements through December 2019.

These units were originally built with scrubbers and PPL Montana has entered into a long-term contract to purchase the limestone requirements for these units.  The contract extends through December 2030.

Coal supply contracts are in place to purchase low-sulfur coal with defined quality characteristics and specifications for PPL Montana's Corette plant.  The contracts covered 100% of the plant's coal requirements in 2012 and similar contracts are in place to supply 100% of the expected coal requirements through 2014.

Oil and Natural Gas

Pennsylvania

PPL Generation's Martins Creek Units 3 and 4 burn both oil and natural gas.  During 2012, 100% of the physical gas requirements for the Martins Creek units were purchased on the spot market while oil requirements were supplied from inventory.  At December 31, 2012, there were no long-term agreementsfuel source for oil or natural gas for these units.

Short-term and long-term gas transportation contracts are in place for approximately 38%each of the maximum daily requirements of the Lower Mt. Bethel facility.  During 2012, 100% of the physical gas requirements were purchased on the spot market.

In 2008, PPL EnergyPlus acquired the rights to an existing long-term tolling agreement associated with the capacity and energy of the Ironwood Facility.  In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility.  See Note 10 to the Financial Statements for additional information.  Beginning in 2010, PPL EnergyPlus has long-term transportation contracts that can deliver up to approximately 25% of Ironwood's maximum daily gas requirements.  Daily gas requirements can also be met through a combination of short-term transportation capacity release transactions coupled with upstream supply.  PPL EnergyPlus currently has no long-term physical gas contracts.  During 2012, 100% of the physical gas requirements were purchased on the spot market.
Talen Energy's plants.

Nuclear

The nuclear fuel cycle consists of several material and service components: the mining and milling of uranium ore to produce uranium concentrates; the conversion of these concentrates into uranium hexafluoride, a gas component; the enrichment of the hexafluoride gas; the fabrication of fuel assemblies for insertion and use in the reactor core; and the temporary storage and final disposal of spent nuclear fuel.

PPL Susquehanna Nuclear has a portfolio of supply contracts, with varying expiration dates, for nuclear fuel materials and services. These contracts are expected to provide sufficient fuel to permit Unit 1 to operate into the first quarter of 20162020 and Unit 2 to operate into the first quarter of 2017.  PPL2019. Susquehanna Nuclear anticipates entering into additional contracts to ensure continued operation of the nuclear units.
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Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel, but there is no definitive date by which a repository will be operational.  As a result, it was necessary to expand Susquehanna'sSusquehanna Nuclear has an on-site spent fuel storage capacity.  To support this expansion, PPL Susquehanna contracted for the design and construction of a spent fuel storage facility employing dry cask fuel storage technology.  The facility is modular, so that additional storage capacity can be added as needed.  The facility began receiving spent nuclear fuel in 1999.  PPL Susquehanna estimates, under current operating conditions, that there is sufficient storage capacity intechnology, which, together with the spent nuclear fuel pools, andhas the on-sitecapacity to accommodate spent fuel expected to be discharged through 2017. This spent fuel storage facility at Susquehannais currently in the process of being expanded to accommodate spent fuel discharged through approximately 2017.  If necessary, the on-siteadditional spent fuel storage, facility can be expanded,and assuming appropriate regulatory approvals are obtained, additional expansion will take place in the future such that, together, the spent fuel pools and the expanded dry fuel storage facility will accommodate all of the spent nuclear fuel expected to be discharged through 2044, the current licensed life of the plant.

In 1996, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the Nuclear Waste Policy Act imposed on the DOE an unconditional obligation to begin accepting spent nuclear fuel on or before January 31, 1998.  In January 2004, PPL Susquehanna filed suit in the U.S. Court of Federal Claims for unspecified damages suffered as a result of the DOE's breach of its contract to accept and dispose of spent nuclear fuel.  In May 2011, the partiesSusquehanna Nuclear entered into a settlement agreement which resolved all claimswith the U.S. Government relating to Susquehanna Nuclear's 2004 lawsuit against the U.S. Government for partial breach of PPLthe standard contract for disposal of spent nuclear fuel. The settlement included reimbursement of certain costs to store spent nuclear fuel at the Susquehanna through December 2013.  PPL Susquehanna has received payments for claims through 2011.  PPL Susquehanna is eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that arenuclear plant incurred through December 31, 2013.2013, and Susquehanna Nuclear received payments for its claimed costs for those periods. In exchange, PPL Susquehanna hasNuclear waived any claims against the United States governmentU.S. Government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna nuclear plant through December 31, 2013. In January 2014, Susquehanna Nuclear entered into an addendum to that agreement to extend the settlement agreement on the same terms for an additional three years to the end of 2016. Susquehanna Nuclear expects to enter into discussions with the DOE this year to further extend the settlement agreement beyond 2016.
Natural Gas and Oil

Energy Marketing
Talen Energy manages natural gas and oil supply utilizing a combination of contracted purchases, spot market purchases and storage for the commodities and pipeline capacity. The amount and duration of contracted capacity varies due to factors including fuel availability, economic considerations and plant location on the pipeline grid. Talen Energy has various short and

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PPL EnergyPlus sells the capacity and electricity produced by PPL Generation subsidiaries, along with purchased power, FTRs, natural gas, oil, uranium, emission allowances and RECs in competitive wholesale and competitive retail markets.

Purchases and sales at the wholesale level are made at competitive prices under FERC market-based prices.  PPL EnergyPlus is licensed to provide retail electric supply to customers in Delaware, the DistrictTable of Columbia, Maryland, New Jersey, Montana and Pennsylvania and licensed to provide retailContents

long-term natural gas supply to customersand transportation contracts in Delaware, Maryland, New Jersey, New Yorkplace; however, the majority of the natural gas supply needs are satisfied with short-term transactions on a spot basis.

Oil requirements are normally supplied by inventory and Pennsylvania.  Withinreplenished through purchases on the constraints of its hedging policy, PPL EnergyPlusspot market.

Coal

Talen Energy actively manages its portfolioscoal requirements by purchasing coal from mines located in central and northern Appalachia and Colorado for its plants located within PJM and from mines located adjacent to the Colstrip facility in Montana. Coal is delivered by rail, barge or conveyor. Reliability of energycoal deliveries can be affected from time to time by a number of factors including fluctuations in demand, coal mine production issues and energy-related productsother supplier or transporter operating difficulties. Coal inventory is maintained at levels estimated to optimizebe necessary to avoid operational disruptions at coal-fired generating units. Long-term supply contracts support adequate levels of coal inventory and are augmented with spot market purchases, as needed. Talen Energy has long-term supply agreements through 2018 for plants located in PJM and for the Colstrip plant through 2019. The contracts in place are expected to provide 62% of 2016 requirements.

In addition, certain of Talen Energy's plants are equipped with flue gas desulfurization equipment or Scrubbers, which use limestone in their valueoperations. Talen Energy has entered into limestone contracts with suppliers that will provide limestone for the plants located in PJM through 2016 and for the Colstrip plant through 2030 and are expected to limit exposure to price fluctuations.  provide 100% of 2016 requirements.

See "Commodity Volumetric Activity" in Note 1910 to the Financial Statements for additional information on Talen Energy's ownership interest in and cost sharing arrangement related to Colstrip.

ACQUISITIONS AND DIVESTITURES
Completion DateCapacity (a)Markets
Acquisitions:
MACH GenNovember 20152,344 MWNYISO, ISO-NE, WECC
RJS PowerJune 20155,182 MWPJM, ERCOT, ISO-NE
Divestitures:
IronwoodFebruary 2016661 MWPJM
C.P. CraneFebruary 2016402 MWPJM
Talen Renewable EnergyNovember 201519 MWVarious
Montana Hydroelectric BusinessNovember 2014633 MWWECC
Announced Divestitures:
Holtwood and Lake WallenpaupackMarch 2016 (b)308 MWPJM
(a)Based on summer rating.
(b)Anticipated closing date.

See Note 6 to the strategies PPLFinancial Statements for additional information on acquisitions and divestitures.

FRANCHISES AND LICENSES

Talen Energy Supply employsMarketing has a license from the DOE to optimizeexport electricity to Canada. Talen Energy Marketing also has a permit from the National Energy Board of Canada to export firm and interruptible electricity from Canada to the United States.

Susquehanna Nuclear operates Units 1 and 2 pursuant to NRC operating licenses that expire in 2042 for Unit 1 and in 2044 for Unit 2. In 2008, a Talen Energy subsidiary, Bell Bend, LLC, submitted a COLA to the NRC for a new nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna nuclear plant. Also in 2008, the COLA was formally docketed and accepted for review by the NRC. Talen Energy does not expect the COLA review process with the NRC to be completed prior to 2018. See Note 6 to the Financial Statements for additional information.
Holtwood, LLC, a subsidiary of Talen Generation that owns hydroelectric generating operations in Pennsylvania, operates the Holtwood and Lake Wallenpaupack hydroelectric generating plants pursuant to FERC-granted licenses that expire in 2030 and 2045, respectively. In 2015, Talen Energy announced that it agreed to sell these facilities. The sale is expected to close in March 2016. In connection with the relicensing of these generating facilities, applicable law permits the FERC to relicense the original licensee or license a new licensee or allow the U.S. government to take over the facility. If the original licensee is not

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relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of its wholesale and retail energy portfolio.the property taken, plus reasonable damages to other property affected by the lack of relicensing.

Competition
COMPETITION

Since the early 1990s, there has been increased competition in U.S. energy markets because of federal and state competitive market initiatives. WhileAlthough some states such as Pennsylvania and Montana, have created a competitive market for electricity generation, other states continue to consider different types of regulatory initiatives concerning competition in the power and gas industry.industries. Some states that were considering creating competitive markets have slowed their plans or postponed further consideration. In addition, states that have created competitive markets have, from time to time, considered new market rules and re-regulation measures that could result in more limited opportunities for competitive energy suppliers. Interest in re-regulation, however, has slowed dueHowever, these initiatives have not fully developed as a result of various efforts by industry participants to prevent the current environmenterosion of declining power prices.the competitive market structure. As such, the markets in which PPLTalen Energy Supply participates are highly competitive.

PPLThe power generation business is a regional business that is diverse in terms of industry structure and fundamentals. Demand for electricity may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generation facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Talen Energy Supply faces competition in wholesale markets for available energy, capacity and ancillary services. Competition is impacted by electricity and fuel prices, congestion along the power grid, subsidies provided by state and federal governments for new generation facilities, new market entrants, construction by others of new generating assets, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. PPLIn retail power markets, Talen Energy Supply primarily competes with other electricity suppliers based on its ability to aggregate generation supply at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities, ISOs and ISOs.RTOs. Competitors in wholesale power markets include regulated utilities, industrial companies, NUGs, competitive subsidiaries of regulated utilities, financial institutions and other energy marketers. See "Item 1A. Risk Factors - RisksFactors-Risks Related to Supply Segment" and PPL's and PPL Energy Supply'sOur Business," "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview"Operations" and NoteNotes 11 and 15 to the Financial Statements for more information concerning the risks faced with respect to competitive energy markets.

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Franchise and Licenses

See "Energy Marketing" above for a discussion of PPL EnergyPlus' licenses in various states.  PPL EnergyPlus also has an export license from the DOE to sell capacity and/or energy to electric utilities in Canada.

PPL Susquehanna operates Units 1 and 2 pursuant to NRC operating licenses that expire in 2042 for Unit 1 and in 2044 for Unit 2.

In 2008, a PPL Energy Supply subsidiary, PPL Bell Bend, LLC, submitted a COLA to the NRC for a new nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna plant.  Also in 2008, the COLA was formally docketed and accepted for review by the NRC.  PPL Bell Bend, LLC does not expect to complete the COLA review process with the NRC prior to 2015.  See Note 8 to Financial Statements for additional information.

PPL Holtwood operates the Holtwood hydroelectric generating plant pursuant to a FERC-granted license that expires in 2030.  In October 2009, the FERC approved the request to expand the Holtwood plant.  See Note 8 to the Financial Statements for additional information.  PPL Holtwood operates the Wallenpaupack hydroelectric generating plant pursuant to a FERC-granted license that expires in 2044.

PPL's 11 hydroelectric facilities and one storage reservoir in Montana are licensed by the FERC.  The Thompson Falls and Kerr licenses expire in 2025 and 2035, the licenses for the nine Missouri-Madison facilities expire in 2040, and the license for the Mystic facility expires in 2050.

In connection with the relicensing of these generating facilities, applicable law permits the FERC to relicense the original licensee or license a new licensee or allow the U.S. government to take over the facility.  If the original licensee is not relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of the property taken, plus reasonable damages to other property affected by the lack of relicensing.  See Note 15 to the Financial Statements for additional information on the Kerr Dam license.

·
Other Corporate Functions (PPL)

PPL Services provides corporate functions such as financial, legal, human resources and information technology services.  Most of PPL Services' costs are charged directly to the respective PPL subsidiaries for the services provided or are indirectly charged to applicable subsidiaries based on an average of the subsidiaries' relative invested capital, operation and maintenance expenses and number of employees.

PPL Capital Funding, PPL's financing subsidiary, provides financing for the operations of PPL and certain subsidiaries, but PPL Capital Funding's costs are not charged to any Registrant other than PPL.  PPL Capital Funding participated significantly in the financing for the acquisitions of LKE and WPD Midlands.  The associated financing costs, as well as the financing costs associated with prior issuances of certain other PPL Capital Funding securities, have been and will continue to be assigned to the appropriate segments for purposes of PPL management's assessment of segment performance.  PPL's recent growth in rate-regulated businesses provides the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that further enables PPL to support targeted credit profiles cost effectively across all of PPL's rated companies.  As a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing by the operating companies, as appropriate.  Beginning in 2013, the proceeds and the financing costs associated primarily with PPL Capital Funding's future securities issuances are not expected to be directly assignable or allocable to any segment.

Also, the costs of certain other miscellaneous corporate level activities are not charged to any subsidiaries or allocated or assigned to any segment for purposes of assessing performance by PPL management.

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

SEASONALITY

The demand for and market prices of electricity and natural gas are affected by weather. As a result, the Registrants'Talen Energy's operating results in the future may fluctuate substantially on a seasonal basis, especially when more severe weather conditions such as heat waves or extreme winter weather make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities owned, the retail load served and the terms of contracts to purchase or sell electricity. See "Financial Condition"Item 1A. Risk Factors - LiquidityRisks Related to Our Business" and Capital Resources - Environmental"Environmental Matters" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations"below for additional information regarding climate change.

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FINANCIAL CONDITION

See the Registrants'"Financial Condition" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for this information.

CAPITAL EXPENDITURE REQUIREMENTS

See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in the Registrants' "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information concerning the $2.4 billion of projected capital expenditure requirements for 20132016 through 2017.  See Note 15 to the Financial Statements for additional information concerning the potential impact on capital expenditures from environmental matters.

ENVIRONMENTAL MATTERS

The Registrants are subject to certain existing and developing federal, regional, state and local laws and regulations with respect to air and water quality, land use and other environmental matters.  The EPA is2020. Included in the processprojections are $137 million of proposing and finalizing an unprecedented number of environmental regulations that will directly affect the electricity industry.  These initiatives cover air, water and waste.  See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in the Registrants' "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information concerning environmental capital expenditures during 2012 and projected environmental capital expenditures for the years 2013-2017.  Also, see "Environmental Matters" in Note 15 to the Financial Statements for additional information.  To comply with primarily air-related environmental requirements, PPL's forecast for capital expenditures reflects awhich reflect Talen Energy's best estimate projection of capital expenditures that may be required within the next five years. Such projections are $1.1 billion for LG&E, $1.2 billion for KU and $246 million for PPL Energy Supply.  Actual costs (including capital, emission allowance purchases and operational modifications) may be significantly lower or higher depending on the final compliance requirements and market conditions. Environmental compliance costs incurred by LG&E and KU are subject to recovery through a rate recovery mechanism.  See Note 6 to the Financial Statements for additional information.

The Registrants are unable to predict the ultimate effect of evolving environmental laws and regulations upon their existing and proposed facilities and operations and competitive positions.  In complying with statutes, regulations and actions by regulatory bodies involving environmental matters, including, among other things, air and water quality, GHG emissions, hazardous and solid waste management and disposal, and regulation of toxic substances, PPL's and LKE's subsidiariesTalen Energy also may be required to modify, replace or cease operating certain of their facilities.  PPL's and LKE's subsidiaries may also incur significantenvironmental-related capital expenditures and operating expenses, in amounts which are not now determinable, but could be significant. See "Environmental Matters" below for additional information on the potential impact on capital expenditures from environmental matters.


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ENVIRONMENTAL MATTERS

Environmental Laws and Regulations

Extensive federal, state and local environmental laws and regulations are applicable to Talen Energy's air emissions, water discharges and the management of hazardous and solid waste, as well as other aspects of its business.  In addition, many of these environmental considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost for their products or their demand for Talen Energy's services.

It may be necessary for Talen Energy to modify, curtail, replace or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations and other requirements imposed by regulatory bodies, courts or environmental groups. Talen Energy may incur costs to comply with environmental laws and regulations, including increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions, which could be material.  Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.  

The following is a discussion of the more significant environmental matters impacting Talen Energy's business.

CSAPR

The EPA's CSAPR addresses the interstate transport of fine particulates and ozone by regulating emissions of sulfur dioxide and nitrogen oxide. CSAPR establishes interstate allowance trading programs for sulfur dioxide and nitrogen oxide emissions from fossil-fuel fired plants for 28 states in two phases: Phase 1 trading commenced in January 2015, and Phase 2 trading is expected to commence in 2017. Although Talen Energy does not currently anticipate significant costs to comply with these programs, changes in market or operating conditions, or significant regulatory changes, could result in impacts that are greater than anticipated. Talen Energy is evaluating the EPA's recently released "CSAPR Update Rule" proposal which recommends more stringent ozone season nitrogen oxide budgets for 23 states, including several where Talen Energy owns affected generation. Additional capital and/or operating and maintenance expenses could be imposed on Talen Energy plants in Maryland, New Jersey, New York, Pennsylvania and Texas as a result of this action. Legal challenges to CSAPR are on-going in federal and state court.
NAAQS

In 2008, the EPA revised downward the NAAQS for ozone.  As a result, states in the ozone transport region (OTR), including Pennsylvania, Maryland, Massachusetts, New York and New Jersey, are required by the Clean Air Act to impose additional reductions in nitrogen oxide emissions based upon reasonably available control technologies (RACT).  PADEP is expected to finalize a RACT rule by the end of the first quarter of 2016 that requires some fossil-fuel fired power plants in Pennsylvania to operate at more stringent nitrogen oxide emission rates starting in 2017. Maryland coal plants operated at reduced nitrogen oxide emission rates during the 2015 ozone season as a result of an emergency action issued by the Governor of Maryland (which later became a final rule) and in November 2015 the MDE promulgated additional nitrogen oxide regulations for Maryland coal plants that require even more stringent operations starting no later than June 2020. In October 2015, the EPA released a final rule that strengthened the NAAQS for ozone. This could lead to even further nitrogen oxide reductions for Talen Energy's fossil-fuel fired plants within and outside of the OTR. State and federal efforts to address interstate transport issues associated with ozone NAAQS, including increased pressure by state environmental agencies and environmental groups to further reduce nitrogen oxide emissions from plants with selective catalytic reduction technology, and updated transport rules such as that proposed by EPA in December 2015 (as discussed above), could additionally lead to further emission reductions and increased compliance costs.
In 2010, the EPA finalized a more stringent NAAQS for sulfur dioxide and required states to identify areas that meet the standard and areas that are in non-attainment or are unclassifiable.  In July 2013, the EPA finalized non-attainment designations for parts of the country where attainment is due by 2018.  States are working on designations for other areas pursuant to a consent decree between the EPA and Sierra Club approved in March 2015 with 2017 or 2020 deadlines, depending on which designation methodology (modeling or monitoring) is selected. Several of Talen Energy's plants are in areas being evaluated for designation.
Until final rules are promulgated, all non-attainment designations are finalized, and state compliance plans are developed, Talen Energy cannot predict the ultimate outcome of the new NAAQS for ozone and sulfur dioxide on its fleet or plants, or whether they may have a material adverse effect on Talen Energy's financial condition or results of operations. Talen Energy anticipates

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that some of the measures required for compliance with the CSAPR (as discussed above) or the MATS and Regional Haze Rules (as discussed below), will help to achieve compliance.
MATS

In February 2012, the EPA finalized a rule (known as the MATS Rule) requiring reductions of mercury and other hazardous air pollutants from fossil-fuel fired power plants by April 2015 with one-and two-year extension opportunities. Subsequently, the U.S. Supreme Court determined that the EPA acted unreasonably by refusing to consider costs when determining whether the MATS regulation was appropriate and necessary. To address the Supreme Court action, the DC Circuit in December 2015 remanded the MATS Rule to the EPA to incorporate a revised appropriate and necessary finding. The EPA has since issued a proposed supplemental finding on cost, claiming that the regulation was appropriate and necessary. The EPA has committed to finalizing the Rule by April 2016. The existing MATS Rule remains in effect. Separate from the EPA's MATS Rule, several states, including Montana and Maryland where Talen Energy owns affected facilities, have enacted regulations requiring mercury emission reductions from coal plants. Talen Energy cannot currently predict whether any costs necessary to comply with the EPA's MATS Rule or similar regulations will have a material adverse effect on Talen Energy's financial condition or results of operations.
Regional Haze

The EPA's regional haze programs were developed under the Clean Air Act to eliminate man-made visibility degradation by 2064.  Under the programs, states are required to make reasonable progress every decade, through the application of, among other things, Best Available Retrofit Technology (BART) on power plants commissioned between 1962 and 1977. The primary power plant emissions affecting visibility are sulfur dioxide, nitrogen oxides and particulates. While the focus of regional haze regulation previously was on the western U.S., in December 2015, a final federal implementation plan for Texas was released with an emphasis on coal plants. Minimal impacts are anticipated to Talen Energy's gas fleet in Texas.
As for the eastern U.S., the EPA had determined that region-wide reductions under the CSAPR trading program could, in most instances, be utilized under state programs to satisfy BART requirements for sulfur dioxide and nitrogen oxides. However, the EPA's determination is being challenged by environmental groups. In September 2015, the Third Circuit Court of Appeals vacated portions of the EPA's approval of Pennsylvania's regional haze state implementation plan and remanded the rule to the EPA for further consideration. Talen Energy is unable to determine at this time if the future impacts of regional haze regulation on Talen Energy plants in the eastern U.S. will have a material adverse effect on Talen Energy's financial condition or results of operations. See Note 11 to the Financial Statements for information on a legal decision issued by the Ninth Circuit Court of Appeals in a case involving Talen Montana challenging the EPA's final Regional Haze Federal Implementation Plan for Montana.
New Source Review (NSR)

The EPA has continued its NSR enforcement efforts targeting coal-fired generating plants.  The EPA has alleged that modification of these plants has increased their emissions and, consequently, that they are subject to stringent NSR requirements under the Clean Air Act.  Talen Energy has responded to several information requests from the EPA, but has received no further substantive communications from the EPA related to those requests since providing its responses.  See Note 11 to the Financial Statements for information on a lawsuit filed by environmental groups in March 2013 against Talen Montana and other owners of Colstrip related to NSR.
Climate Change

Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to Talen Energy's generation assets, as well as impacts on Talen Energy's customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where Talen Energy's generation facilities use river water for cooling. Federal and state initiatives to prepare energy assets and infrastructure for the impacts of climate change, such as those actions driven by President Obama's 2013 Climate Action Plan (discussed further below), could result in binding obligations to physically protect Talen Energy's generation assets from climate change impacts.
Talen Energy cannot currently predict whether its businesses will experience these potential risks or whether any related costs will have a material adverse effect on Talen Energy's financial condition or results of operations.

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GHG Regulations & Tort Litigation

In April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that applied beginning with 2012 model year vehicles.  The EPA stated that this standard authorizes regulation of carbon dioxide emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act.  Following legal challenges, in June 2014, the U.S. Supreme Court ruled that the EPA has the authority to regulate carbon dioxide emissions under the Clean Air Act, but only for stationary sources that would otherwise have been subject to these provisions due to significant increases in emissions of other regulated pollutants.  As a result, any new sources or major modifications to an existing GHG source causing a net significant increase in carbon dioxide emissions must comply with best achievable control technology (BACT) permit limits for carbon dioxide if it would otherwise be subject to BACT or lowest achievable emissions rate limits due to significant increases in other regulated pollutants. EPA is expected to propose a de minimis threshold for such permits in June 2016.
In June 2013, President Obama released his Climate Action Plan reiterating the goal of reducing GHG emissions in the U.S. through such actions as regulating power plant emissions, promoting increased use of renewables and clean energy technology, and establishing more restrictive energy efficiency standards. In October 2015, the EPA finalized carbon dioxide regulations for new and existing power plants, and the EPA has proposed a federal implementation plan that would apply to any states that fail to submit an acceptable state plan for the existing plant rule. EPA's existing plant rule has been stayed by the U.S. Supreme Court until all legal challenges to the rule have been resolved. The new plant rule remains in effect and challenges are also outstanding in federal court. Implementation of the new and existing power plant rules could have a significant industry-wide impact, but at this time Talen Energy is unable to determine if the rules will have a material adverse effect on Talen Energy's financial condition or results of operations.
A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting plants and, although the decided cases to date have not sustained claims brought on the basis of these theories of liability, the law remains unsettled on these claims.
Exemptions for Startup, Shutdown and Malfunction Events

In May 2015, the EPA released a final rule which prohibits states from exempting startup, shutdown and malfunction (SSM) events from compliance requirements in State Implementation Plans (SIPs). The Rule issues a SIP call for each of those states where the SSM provisions in the SIPs of those states fail to meet the EPA's requirements. Affected states, including Arizona, New Jersey, Montana and Texas where Talen Energy owns generation facilities, must submit revised provisions to the EPA in November 2016. Revisions to a SIP or other regulations in other non-affected states where Talen Energy operates could result from this action. The EPA's final rule is being challenged in federal court. Talen Energy cannot currently predict whether revisions to SIPs or other similar regulations will have a material adverse effect on Talen Energy's financial condition or results of operations.
CCRs

The EPA's final rule regulating CCRs, including fly ash, bottom ash and sulfur dioxide scrubber wastes became effective in October 2015. It imposes extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements and closure and post-closure care requirements on CCR impoundments and landfills that are located at active power plants and not closed. Under the rule, the EPA will regulate CCRs as non-hazardous under Subtitle D of RCRA and allow beneficial use of CCRs, with some restrictions. This self-implementing rule requires posting of compliance documentation on a publicly accessible website and is only enforceable through citizen suits. Talen Energy expects that its plants using surface impoundments for management and disposal of CCRs, or that previously managed CCRs and continue to manage wastewaters, will be most impacted by the rule. Requirements for covered CCR impoundments and landfills include commencement or completion of closure activities generally between three and ten years from certain triggering events. Talen Energy anticipates incurring capital or operation and maintenance costs prior to that time to address other requirements of the rule, such as groundwater monitoring and disposal facility modifications, or to implement various compliance strategies. The final CCR Rule is being challenged in federal court.
Talen Energy continues to review the Rule and evaluate financial and operational impacts. During 2015, an increase of $41 million was recorded to existing AROs. Further changes to AROs may be required as estimates are refined and compliance with the rule continues. See Note 18 for information on AROs.

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ELGs and Standards

The EPA's final ELG regulations that revise discharge limitations for steam electric generation wastewater discharge permits became effective in January 2016. The final limitations are based on the EPA's review of available treatment technologies and their capacity for reducing pollutants and include new requirements for fly ash and bottom ash transport water and for scrubber wastewater.  The EPA's final ELG regulations contain requirements that could have a material impact on Talen Energy's coal-fired plants.  At the present time, Talen Energy is evaluating the new requirements. The new ELG limitations and standards will be implemented as each plant's discharge permit is renewed. The compliance period for the new requirements is from November 2018 through the end of 2023, based on the date that the permit is renewed and the applicable deadline negotiated with the agencies for that facility. At this point, Talen Energy is unable to estimate a range of reasonably possible compliance costs. The final ELG regulations are being challenged in federal court.
Seepages and Groundwater Infiltration - Pennsylvania and Montana

Talen Energy has completed or is completing assessments of seepages or groundwater infiltration at various active and retired wastewater basins and landfills at certain of its facilities. Talen Energy has completed or is working with agencies to respond to related notices of violations and implement assessment or abatement measures, where required or applicable. A range of reasonably possible losses cannot currently be estimated and, therefore, Talen Energy is unable to determine if any such abatement measures will have a material adverse effect on Talen Energy's financial condition or results of operations.
In August 2012, Talen Montana entered into an Administrative Order on Consent (AOC) with the MDEQ which establishes a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at the Colstrip power plant.  The AOC requires that within five years, Talen Montana provide financial assurance to the MDEQ for the costs associated with closure and future monitoring of the waste-water treatment facilities.  Talen Montana cannot predict at this time if the actions required under the AOC will create the need to adjust the existing ARO related to this facility. Talen Montana is defending the AOC in litigation brought by environmental groups as discussed in Note 11 to the Financial Statements.
Under the Pennsylvania Clean Streams Law, a subsidiary of Talen Generation is obligated to remediate acid mine drainage at a former mine site and may be required to take additional steps to prevent potential acid mine drainage at a previously capped refuse pile at this mine site. The subsidiary is pumping and treating mine water at the former mine site.
At December 31, 2015, Talen Generation had accrued a discounted liability of $19 million to cover the costs of pumping and treating groundwater at this mine site for 50 years. Talen Energy discounted this liability based on a risk-free rate of 8.41% at the time of the mine closure. Expected undiscounted payments are estimated to be $1 million for each of the years 2016, 2017, 2019, and 2020, $3 million in 2018, and $92 million for work after 2020.
Clean Water Act_316(b) Rule

The EPA's final 316(b) Rule for existing facilities became effective in October 2014 and regulates cooling water intake structures and their impact on aquatic organisms.  States are allowed considerable authority to make site-specific determinations under the Rule which requires existing facilities to choose between several options to reduce impingement and entrainment.  Plants already equipped with closed-cycle cooling, an acceptable option, would likely not incur substantial compliance costs.  Plants equipped with once-through cooling water systems would likely require additional technology to comply with the rule.  Talen Energy is evaluating compliance strategies, but does not presently expect to incur material compliance costs. The EPA's final rule is being challenged in federal court.
Waters of the United States (WOTUS)

In June 2015, the EPA and the U.S. Army Corps of Engineers (Army Corps) published their final rule redefining the term WOTUS. The rule, which became effective in August 2015, identifies six types of categorically jurisdictional waters and two categories of waters for which case-by-case evaluations are needed to determine whether a "significant nexus" exists. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order preventing the EPA from implementing the rule nationwide. Talen Energy will continue to evaluate the rule, and while no material impacts to Talen Energy's financial condition or results of operations are anticipated, the redefinition could impact future development actions, such as plant and gas infrastructure expansions, in the event the stay is lifted. Legal challenges are on-going in federal and state court.
Superfund and Other Remediation

From time to time, Talen Energy undertakes investigative or remedial actions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions

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necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from Talen Energy's operations and undertakes similar actions necessary to resolve environmental matters which arise in the course of normal operations.  Based on analysis to-date, resolution of these environmental matters is not expected to have a material adverse effect on Talen Energy's financial condition or results of operations.
Future investigation or remediation work at sites currently under review, or at sites not currently identified, may result in additional costs for Talen Energy, but at this time Talen Energy is unable to determine if such investigation or remediation work will have a material adverse effect on Talen Energy's financial condition or results of operations.
Other

In addition to the environmental matters discussed above, from time-to-time in the ordinary course of its business, Talen Energy may become involved in other environmental matters or become subject to other environmental statutes, regulations or requirements. In the opinion of management based upon information currently available to Talen Energy, while the outcome of these other environmental matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.

See Note 11 to the Financial Statements for additional information on environmental matters.
REGULATORY MATTERS

Talen Energy operates in a highly regulated industry and is subject to regulation by various federal and state agencies and in the various regions where it conducts business.

Certain of Talen Energy's generation subsidiaries are EWGs that sell electricity into wholesale markets. EWGs are subject to regulation by the FERC, which has authorized these EWGs to sell the electricity generated at market-based prices. A portion of this electricity is sold to Talen Energy Marketing under FERC-jurisdictional power purchase agreements. Susquehanna Nuclear is subject to the jurisdiction of the NRC in connection with the operation of its Susquehanna nuclear units. In addition, certain of Talen Energy's other subsidiaries are subject to the jurisdiction of the NRC in connection with the operation of their fossil plants with respect to certain level and density monitoring devices. Certain operations of Talen Energy are also subject to OSHA and comparable state statutes.

The following is a discussion of the more significant regulatory matters impacting Talen Energy's business.

Proposed Legislation/Initiatives - Pacific Northwest

In January 2016, legislation was proposed in the State of Washington to provide a means of cost recovery to utility owners of coal-fired generating facilities who commit to retire such facilities.  An initiative also was submitted to the Washington legislature that would impose a carbon tax of $25 per ton on fossil fuels in Washington.  The 2016 legislature now has three options relative to the initiative - (i) pass the same into law as drafted; (ii) defer action on the same to the voters in November 2016; or (iii) revise and pass the initiative, sending both the original and amended measures to the November 2016 state-wide ballot. 

In the same time frame, legislation was proposed in the State of Oregon that would double the renewable mandate in Oregon to 50% by 2040 and would limit Oregon utilities' ability to use coal power in Oregon only until 2030, although one utility there would be able to use a small amount thereafter until 2035.  A key provision of the Oregon legislation is that two pending "no coal" initiatives would be withdrawn once the bill becomes law. 

Talen Energy cannot predict whether any legislation seeking to achieve these objectives will be enacted in either state or, if enacted, if such legislation would have a material adverse effect on Talen Energy's financial condition or results of operations.

Electricity - Reliability Standards

The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk power system.  The FERC oversees this process and independently enforces the Reliability Standards.


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The Reliability Standards have the force and effect of law and apply to certain users of the bulk power electricity system, including electric utility companies, generators and marketers.  Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations.

Talen Energy monitors its subsidiaries' compliance with the Reliability Standards and continues to self-report potential violations of certain applicable reliability requirements and submit accompanying mitigation plans, as required.  The resolution of a number of potential violations is pending.

In the course of implementing their programs to ensure compliance with the Reliability Standards by those Talen Energy subsidiaries subject to the standards, certain other instances of potential non-compliance may be identified from time to time.  Talen Energy cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.

Other

In addition to the regulatory matters discussed above, Talen Energy and its subsidiaries are party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. While the outcome of these other regulatory matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.

See Note 11 to the Financial Statements for additional information on regulatory matters.
EMPLOYEE RELATIONS

At December 31, 2012, PPL2015, Talen Energy and its subsidiaries had the following4,981 full-time employees.

PPL Energy Supply (a) 4,733 
PPL Electric 2,311 
LKE
KU 931 
LG&E 991 
LKS 1,380 
Total LKE 3,302 
PPL Global (primarily WPD)6,116 
PPL Services and other1,267 
Total PPL 17,729 

(a)Includesemployees, 2,579 of which were represented by labor unions. These numbers include union employees of mechanical contracting subsidiaries, whose numbers tend to fluctuate due to the nature of this business.

Approximately 5,600 employees, or 48%, of PPL's domestic workforce are members of labor unions, with four IBEW labor unions representing approximately 4,300 employees.  The bargaining agreement with the largest IBEW labor union, which expires in May 2014, covers approximately 1,500 PPL Electric, 1,600 PPL Energy Supply and 400 other employees.  Approximately 700 employees of LG&Emechanical contracting subsidiaries and 70 employeestend to fluctuate due to the nature of KU are represented by an IBEW labor union.  Both LG&E and KU have three-year labor agreements with the IBEW, which expire in November 2014 and August 2015.  The KU IBEW agreement includes a wage reopener in 2014.  Approximately 70 employees of KU are represented by a United Steelworkers of America (USWA) labor union, under an agreement that expires in August 2014.  PPL Montana's largest bargaining unit, an IBEW labor union, represents approximately 260 employees at the Colstrip plant.  The four-year labor agreement expires in April 2016.  PPL Montana's second largest bargaining unit, also an IBEW labor union, represents approximately 80 employees at hydroelectric facilities and the Corette plant, under an agreement that expires in April 2013.

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Approximately 3,900, or 64%, of PPL's U.K. workforce are members of labor unions.  WPD recognizes four unions, the largest of which represents 41% of its union workforce.  WPD's Electricity Business Agreement, which covers approximately 3,850 union employees, may be amended by agreement between WPD and the unions and is terminable with 12 months' notice by either side.mechanical contractors' business.

AVAILABLE INFORMATION

PPL'sTalen Energy's Internet website is www.pplweb.com.  Onwww.talenenergy.com. Under the Investor Center pageheading of that website, PPLTalen Energy provides access to all SEC filings of the Registrants (including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K,8‑K, and amendments to these reports filed or furnished pursuant to Section 13(d) or 15(d)) free of charge, as soon as reasonably practicable after filing or furnishing with the SEC.  Additionally, the Registrants' filings are available at the SEC's website (www.sec.gov) and at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549, or by calling 1-800-SEC-0330.


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ITEM 1A. RISK FACTORS

The RegistrantsWe face various risks associated with theirour businesses. Our businesses, financial condition, cash flows or results of operations could be materially adversely affected by any of these risks. In addition, this report also contains forward-looking and other statements about our businesses that are subject to numerous risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1511 to the Financial Statements for more information concerning the risks described below and for other risks, uncertainties and factors that could impact our businesses and financial results.

As used in this Item 1A., the terms "we," "our" and "us" generally refer to PPLTalen Energy and its consolidated subsidiaries taken as a whole, or to PPLwhole.

Talen Energy's business was formed on June 1, 2015, by the spinoff of Talen Energy Supply and its consolidated subsidiaries taken as a whole within the Supply segment discussions, or PPL Electricsubsequent combination of that business with RJS Power, to form an independent, publicly traded company (collectively, the "Talen Transactions"). See Notes 1, 3 and its consolidated subsidiaries taken as a whole within6 to the Pennsylvania Regulated segment discussion, or LKE and its consolidated subsidiaries taken as a whole within the Kentucky Regulated segment discussion.Financial Statements for additional information.

Risks Related to All Segments

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

We plan to selectively pursue growth of generation, transmission and distribution capacity, which involves a number of uncertainties and may not achieve the desired financial results.

We plan to pursue expansion of our generation, transmission and distribution capacity over the next several years through power uprates at certain of our existing power plants, the potential construction of new power plants, the potential acquisition of existing plants, the potential construction or acquisition of transmission and distribution projects and capital investments to upgrade transmission and distribution infrastructure.  We will rigorously scrutinize opportunities to expand our generating capability and may determine not to proceed with any expansion.  These types of projects involve numerous risks.  Any planned power uprates could result in cost overruns, reduced plant efficiency and higher operating and other costs.  With respect to the construction of new plants, the acquisition of existing plants, or the construction or acquisition of transmission and distribution projects, we may be required to expend significant sums for preliminary engineering, permitting, resource exploration, legal and other expenses before it can be established whether a project is feasible, economically attractive or capable of being financed.  Expansion in our regulated businesses is dependent on future load or service requirements and subject to applicable regulatory processes.  The success of both a new or acquired project would likely be contingent, among other things, upon the negotiation of satisfactory operating contracts, obtaining acceptable financing and maintaining acceptable credit ratings, as well as receipt of required and appropriate governmental approvals.  If we were unable to complete construction or expansion of a project, we may not be able to recover our investment in the project.  Furthermore, we might be unable to operate any new or acquired plants as efficiently as projected, which could result in higher than projected operating and other costs and reduced earnings.Our Business

Adverse conditions in the economic and financial markets in which we operateconditions could adversely affect our financial condition and results of operations.

Adverse economic conditions in the financial markets during 2008 and the associated contraction of liquidity in the wholesale energy markets contributed significantly to declines in wholesale energyelectricity prices and hashave significantly impacted our earnings since the second half of 2008.earnings. The breadth and depth of these negative economic conditions had a wide-ranging impact on the U.S. and U.K. business environment, including our businesses. As a result ofIn addition, adverse economic conditions also reduce the economic downturn, demand for energy commodities declined significantly.commodities. This reduced demand continues to impact the key domestic wholesale energyelectricity markets we serve (such as PJM) and our Pennsylvania and Kentucky utility businesses.serve. The combination of lower demand for power and increased supply of natural gas has put downward price pressure on wholesale energyelectricity markets in general, further impacting our energy marketing results. In general, current economic and commodity market conditions will continue to challenge predictability regardingimpact our unhedged future energy margins, liquidity, earnings growth and overall financial condition. In addition, adverse economic conditions, declines in wholesale electricity prices, reduced demand for power and other factors may negatively impact the trading price of our common stock and impact forecasted cash flow, which may require us to evaluate our assets for impairment. Any such impairment could have a material impact on our results of operations and financial statements.
Adverse changes in commodity prices and related costs may decrease our future energy margins, which could adversely affect our earnings and cash flows.
Our energy margins, or the amount by which our revenues from the sale of power exceed our costs to supply power, are impacted by changes in market prices for electricity, fuel, fuel transportation, emission allowances, RECs, electricity capacity and related congestion charges and other costs. Unlike most commodities, the limited ability to store electricity requires that it must be consumed at the time of production. As a result, wholesale market prices for electricity may fluctuate substantially over relatively short time periods and can be unpredictable. Among the factors that influence such prices are:
demand for electricity;
supply of electricity available from current or new generation resources;
variable production costs, primarily fuel (and associated transportation costs) and emission allowance expense for the generation resources used to meet the demand for electricity;
transmission capacity and service into, or out of, markets served;
changes in the regulatory framework for wholesale power markets;
liquidity in the wholesale electricity market, as well as general creditworthiness of key participants in the market; and
weather and economic conditions affecting demand for or the price of electricity or the facilities necessary to deliver electricity.
Our risk management policy and procedures relating to electricity and fuel prices, interest rates and counterparty credit and non-performance risks may not work as planned, and we may suffer economic losses despite such programs.
We actively manage the market risk inherent in our generation and energy marketing activities, as well as our debt and counterparty credit positions. We have implemented procedures to monitor compliance with our risk management policy, including independent validation of transaction and market prices, verification of risk and transaction limits, portfolio stress tests, sensitivity analyses and daily portfolio reporting of various risk management metrics. Nonetheless, our risk management policy may not work as planned. For example, actual electricity and fuel prices may be significantly different or more volatile

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Our businesses are heavily dependent on creditTable of Contents

than the historical trends and capital, among other things, for capital expendituresassumptions upon which we based our risk management calculations. Additionally, unforeseen market disruptions could decrease market depth and providing collateral to support hedging inliquidity, negatively impacting our energy marketing business.  Global bank credit capacity declined and the cost of renewing or establishing new credit facilities increased significantly in 2008, primarily as a result of general credit concerns nationwide, introducing uncertainties as to our businesses' ability to enter into long-term energynew transactions. We enter into financial contracts to hedge commodity "basis risk," and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery. Similarly, interest rates could change in significant ways that our risk management procedures were not designed to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position.
In addition, our trading, marketing and hedging activities are exposed to counterparty credit risk and market liquidity risk. As part of our risk management policy, we have established credit procedures to evaluate counterparty credit risk. However, if counterparties fail to perform, we may be forced to enter into alternative arrangements at then-current market prices. In that event, our financial results could be adversely affected.
We do not always hedge against risks associated with electricity and fuel price volatility.
We attempt to mitigate risks associated with satisfying our contractual electricity sales obligations by either reserving generation capacity to deliver electricity or purchasing the necessary financial or physical products and services through competitive markets to satisfy our net firm sales contracts. We also routinely enter into contracts, such as fuel and electricity purchase and sale commitments, or reliably estimate the longer-term costto hedge our exposure to fuel requirements and availability of credit.  Although bank credit conditions have improved since mid-2009, and we currently expect to have adequate access to needed credit and capitalother electricity-related commodities. However, based on current conditions, deteriorationeconomic and other considerations, we may decide not to hedge the entire exposure. To the extent we do not hedge against such exposure and fuel requirements and applicable commodity prices change in ways that would be adverse to us, our results of operations and financial position may be adversely affected. To the extent we do hedge, those hedges may not ultimately prove to be effective.
The accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to physically and financially hedge our exposure to market risk with respect to electricity sales from our generation assets, fuel utilized by those assets and emission allowances.
We generally attempt to balance our fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are recorded on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for the NPNS exception. Specific criteria are required in order to elect the NPNS exception, which permits qualifying hedges to be treated under the accrual accounting method. All economic hedges may not necessarily qualify for the NPNS exception, or we may elect not to utilize the NPNS exception. As a result, our quarterly and annual results are subject to significant fluctuations caused by changes in market prices.
We are exposed to operational, price and credit risks associated with selling and marketing products in the wholesale and retail electricity markets.
We sell electricity in wholesale markets under market-based rates throughout the U.S. and also enter into short-term agreements to market available electricity and capacity from our generation assets with the expectation of profiting from market price fluctuations. It is possible, however, that market price fluctuations and the absence of long-term agreements could adversely impact our profitability and results of operations.
To the extent that we do have agreements in place to deliver firm electricity and capacity and fail to do so, we could be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement electricity or capacity and the contract price of any undelivered capacity or electricity. Depending on price volatility in the wholesale electricity markets, such damages could be significant. Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause significant increases in the market price of replacement capacity and electricity.
Our wholesale power sales agreements typically include provisions requiring us to post collateral for the benefit of our counterparties if the market price of electricity varies from the contract prices in excess of certain predetermined amounts. We currently believe that we have sufficient liquidity to fulfill our potential collateral obligations under these power sales contracts. However, our obligation to post collateral could exceed the amount of our facilities or our ability to increase our facilities could be limited by financial markets or other factors.
We also face credit risk that counterparties with whom we contract in both the wholesale and retail markets will default in their performance, in which case we may have to sell our electricity into a lower-priced market or make purchases in a higher-priced

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market than existed at the inception of the contract. Whenever feasible, we attempt to mitigate these risks using various means, including agreements that require our counterparties to post collateral for our benefit if the market price of electricity varies from the contract price in excess of certain predetermined amounts. However, there can be no assurance that we will avoid counterparty nonperformance risk, including bankruptcy, which could adversely impact our ability to meet our obligations to other parties, which could in turn subject us to claims for damages.
The full-requirements sales contracts that Talen Energy Marketing is awarded do not provide for specific levels of load and actual load significantly below or above our forecasts could adversely affect our energy margins.
We generally hedge our full-requirements sales contracts with our own generation or electricity purchases from third parties. If the actual load is significantly lower than the expected load, we may be required to resell power at a lower price than was contracted for to supply the load obligation, resulting in a financial condition and liquidity.  Additionally, regulationsloss. Alternatively, a significant increase in load could adversely affect our energy margins because we are required under the terms of full-requirements sales contracts to provide the electricity necessary to fulfill increased demand at the contract price, which could be adoptedlower than the cost to implementprocure additional electricity on the Dodd-Frank Act and Basel IIIopen market or could mean that we are required to operate our plants to meet the requirements despite the fact that it may be unprofitable to do so. Therefore, any significant decrease or increase in Europe may impose requirementsload compared with our forecasts could have a material adverse effect on our businessesresults of operations and the businesses of others with whom we contract such as banks or other counterparties, or simply result in increased costs to conduct our business or access sources of capital and liquidity upon which the conduct of our businesses is dependent.

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financial position.
Our operating revenues could fluctuate on a seasonal basis, especially as a result of extreme weather conditions.

Our businesses are subject to seasonal demand cycles. For example, in some markets demand for, and market prices of, electricity peak during hot summer months, while in other markets such peaks occur in cold winter months. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis if weather conditions such as heat waves, extreme cold, unseasonably mild weather or severe storms occur. The patterns of these fluctuations may change depending on the type and location of our facilities and the terms of our contracts to sell electricity.

Operating expenses could be affected by weather conditions, including storms, as well as by significant man-mademanmade or accidental disturbances, including terrorism or natural disasters.

Weather and these other factors can significantly affect our profitability or operations by causing outages, damaging infrastructure and requiring significant repair costs. Storm outages and damage often either or both directly decrease revenues and increase expenses, due to reduced usage and higher restoration charges.  In addition, weathercosts.
We may experience disruptions in our fuel supply, which could adversely affect our ability to operate our generation facilities.
We purchase fuel and other disturbancesproducts consumed during the production of electricity (such as coal, natural gas, oil, water, uranium, lime, limestone and other chemicals) from a number of suppliers. Delivery of these fuels to our facilities is dependent upon the continuing financial viability of contractual counterparties as well as the infrastructure (including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve each generation facility. As a result, we are subject to the risks of disruptions or curtailments in the production of power at our generation facilities if fuel is unavailable at any price or if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Disruption in the delivery of fuel, including disruptions as a result of weather, transportation difficulties, global demand and supply dynamics, labor relations, environmental regulations or the financial viability of our fuel suppliers, could adversely affect our ability to operate our facilities, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations.
We have sold forward a portion of our power in order to lock in long-term prices that we deemed to be favorable at the time we entered into the forward sale contracts. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in our fuel supplies may affect capital marketstherefore require us to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on our financial performance.
We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of electricity may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on our financial performance. Changes in market prices for coal, oil and natural gas may result from the following:

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weather conditions;
seasonality;
demand for energy commodities and general economic conditions;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
additional generating capacity;
availability and levels of storage and inventory for fuel stocks;
natural gas, crude oil, refined products and coal production levels;
changes in market liquidity;
federal, state and foreign governmental regulation and legislation; and
the creditworthiness and liquidity of fuel suppliers and/or transporters and their willingness to do business with us.
Our plant operating characteristics and equipment, particularly at our coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of a specific quality may not be available at any price, or we may not be able to transport such coal to our facilities on a timely basis. In this case, we may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If we have sold forward the power from such a coal facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on our results of operations.
Unforeseen circumstances could cause us to hold excess coal inventories and incur contract termination costs.
Because we enter into guaranteed supply contracts to provide for the amount of coal needed to operate our base load coal-fired generating facilities, we may experience periods where we hold excess amounts of coal. For example, extraordinarily low natural gas prices could cause natural gas to be the more cost-competitive fuel compared to coal for generating electricity, and as a result we may reduce or idle coal-fired generating facilities in favor of operating available alternative natural gas-fired generating facilities. In addition, we may incur costs to terminate supply contracts for coal in excess of our generating requirements. For example, to mitigate the risk of oversupply, we incurred charges of $41 million during 2015 to reduce our contracted coal deliveries.
If the services provided by the transmission facilities that deliver the wholesale power from our generation facilities are inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, any change in the structure and operation of, or the various pricing limitations imposed by, the RTOs and ISOs that operate these transmission facilities may adversely affect the profitability of our generation facilities.
We do not own or control the transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day ahead markets in which we sell electricity. The RTOs and ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, offer caps and other mechanisms to guard against the potential exercise of market power in these markets as well as price limitations. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell electricity and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. Additionally, if the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, the rates for transmission capacity from these facilities are set by others and thus are subject to changes, some of which could be significant. As a result, our financial condition, results of operations and cash flows may be materially adversely affected.
The FERC has issued regulations that require wholesale electricity transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission

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capacity will not be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs and RTOs in applicable markets will efficiently operate transmission networks and provide related services.
Because our generation facilities are part of interconnected regional grids, we face the risk of blackout due to a disruption on a neighboring interconnected system.
Major electric power blackouts are possible and have occurred, which could disrupt electrical service for extended periods of time. If a blackout were to occur, the impact could result in interruptions to our operations, increased costs to replace existing contractual obligations, the possibility of regulatory investigations and potential operational risks to our facilities. Additionally, in response to a blackout, there could be changes or developments in applicable regulations or market structures that could have longer-term impact on our business and results of operations.
We face intense competition in the competitive power generation market, which may adversely affect our ability to operate profitably and generate positive cash flow.
Our generation business is dependent on our ability to operate successfully in a competitive environment and is not assured of any rate of return on capital investments through a regulated rate structure.
Competition is affected by electricity and fuel prices, relative cost of production of energy products, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities, establishment of legislation which favors one form of generation over another, such as investment tax credits or production tax credits, and other factors. These competitive factors may negatively affect our ability to sell electricity and related products and services, as well as the prices that we receive for such products and services, which could adversely affect our results of operations and our ability to grow our business.
We sell our available electricity and capacity products into competitive wholesale markets through contracts of varying duration. Competition in the wholesale electricity markets occurs principally on the basis of the price of products and, to a lesser extent, reliability and availability. We believe that the commencement of commercial operation of new electricity generating facilities in the regional markets where we own or control generation facilities and the evolution of demand side management resources will continue to increase competition in the wholesale electricity markets in those regions, which could have an adverse effect on electricity and capacity prices. We also face competition in the wholesale markets for generation capacity and ancillary services.
Competitors in the wholesale power markets in which we operate include regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities, financial institutions and other energy marketers. We compete against these entities based on the cost of producing our products, which can include costs attributable to our access to credit sources and the levels of unsecured credit extended to our competitors.
In retail power markets, we primarily compete with other electricity suppliers based on our ability to aggregate generation supply at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities, ISOs and RTOs.
Despite federal and state deregulation initiatives, our generation business is still subject to extensive regulation, including requirements that we obtain and comply with government permits and approvals, which may increase our costs, reduce our revenues, or prevent or delay operation of our facilities.
We are required to obtain, and to comply with, numerous permits, approvals, licenses and certificates from federal, state and local governmental agencies. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. In addition, such permits or approvals may be subject to denial, revocation or modification under various circumstances. Failure to obtain or comply with the conditions of permits or approvals, or failure to comply with applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our power delivery and may subject us to penalties and other sanctions. Although various regulators routinely renew existing licenses, renewal could be denied or jeopardized by various factors, including failure to provide adequate financial assurance for closure; local community, political or other opposition; and executive, legislative or regulatory action. Our cost or inability to obtain and comply with the permits and approvals required for our operations could have a material adverse effect on our operations and cash flows.
In addition, our generation subsidiaries sell electricity into the wholesale market. Generally, our generation subsidiaries and our marketing subsidiaries are subject to regulation by the FERC. The FERC has authorized us to sell generation from our

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facilities and power from our marketing subsidiaries at market-based prices. The FERC retains the authority to modify or withdraw our market-based rate authority and to impose "cost of service" rates if it determines that the market is not competitive, that we possess market power or that we are not charging just and reasonable rates. Any reduction by the FERC in the rates we may receive or any unfavorable regulation of our business by state regulators could materially adversely affect our results of operations. In addition, pursuant to PJM's new Capacity Performance construct, we may be subject, in certain PJM emergency events, to economic penalties for generation non-performance, which could be material. See "Item 1. Business-Markets - Recent Market Developments - PJM" in this Form 10-K for additional information.
Our costs to comply with federal, state and local statutes, rules and regulations relating to environmental protection and worker health and safety could be material and could cause the continued operation of certain of our generation facilities to be uneconomic.
Our business is subject to extensive federal, state and local statutes and regulations relating to environmental protection and worker health and safety. These laws and regulations, which have become more stringent over time, impose numerous requirements, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of hazardous materials, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination.
If there is any delay in obtaining any environmental regulatory approvals necessary for our operations or capital projects, or if we fail to obtain, maintain or comply with any such approvals, operations at our affected facilities could be halted, reduced or subjected to additional costs.
For example, the EPA's ELGs and the EPA's CCR Rule could adversely affect our operations and restrict or delay our ability to obtain permits. Moreover, the EPA's Clean Power Plan could have a significant impact on current operations and future growth.opportunities, though it is not possible at this time to predict how this and other pending and/or recently promulgated regulations and laws will impact our business.

We have spent and expect to spend substantial amounts in the future on measures regarding environmental control and compliance, including, but not limited, with respect to pollution control technology. At some of our older generating facilities, it may be uneconomic for us to install necessary controls to comply with new or proposed legislation or regulations, which could cause us to retire those units.
Certain of our operations pose risks of environmental liability due to leakage, migration, emission, releases or spills of hazardous substances to the air, surface or subsurface soils, surface water or groundwater. We may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from our own actions that were in compliance with all applicable laws at the time those actions were taken. Certain environmental laws impose strict as well as joint and several liability (that could result in an entity paying more than its fair share) for costs required to remediate and restore sites. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.
Failure to comply with applicable laws, regulations and permits may result in liability for administrative, civil and/or criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. In addition, private parties may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws, regulations and permits or for personal injury or property damage.
See "Item 1. Business - Environmental Matters" for additional information regarding environmental laws and regulations applicable to our operations.
Our businesses are subject to physical, market and economic risks relating to potential effects of climate change.

Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electric power.  Temperature increaseselectricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could resultdisrupt our operations and cause us to incur significant costs in increased summerpreparing for or decreased winter overall electricity consumption and precipitation changes could result in altered availability of water for hydro generation or plant cooling operations.responding to these effects. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Greenhouse gas regulationClimate change could increasealso affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of our generation plants. See "Item 1. Business - Environmental Matters" for additional information regarding the potential impact of climate change and related regulations on our business.

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The availability and cost of electricemission allowances could negatively impact our costs of operations.
We are required to maintain, through either allocations or purchases, sufficient emission allowances for sulfur dioxide, nitrogen oxide and carbon dioxide to support our operations in the ordinary course of operating our power particularly power generatedgeneration facilities. These allowances are used to meet the obligations imposed on us by fossil fuels,various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Changes in legislative and such increasesregulatory policy, including the promotion of renewable energy, energy efficiency, conservation and self-generation, may adversely impact our business.
Economic downturns, periods of high energy supply costs and other factors can lead to changes in or the development of legislative and regulatory policy designed to promote reductions in energy consumption, increased energy efficiency, renewable energy and self-generation by customers. This focus on conservation, renewable energy, energy efficiency and self-generation may result in a decline in electricity demand, which could have a depressive effect on regional economies.  Reduced economic and consumer activity in turn adversely affect our service areas -- both generally and specificbusiness.
We are subject to certain industriesrisks associated with nuclear generation, including the risk that our nuclear generating facility could become subject to increased security or safety requirements that would increase capital and consumers accustomedoperating expenditures, uncertainties regarding spent nuclear fuel, and uncertainties associated with decommissioning our plant at the end of its licensed life.
Nuclear generation accounted for about 31% of our 2015 competitive power generation output (including output of (i) RJS as of June 2015, (ii) MACH Gen as of November 2015, (iii) certain of our renewables businesses prior to previously lower cost power -- could reduce demand fortheir sale in November 2015 and (iv) the powerfacilities that we generate, markethave announced are to be sold to satisfy the FERC order approving the combination of Talen Energy Supply and deliver.  Also, demand for our energy-related services could be similarly lowered should consumers' preferences or market factors move toward favoring energy efficiency, low-carbon power sources or reduced electric usage.RJS Power). The risks of nuclear generation generally include:

the potential harmful effects on the environment and human health from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
We cannot predictlimitations on the outcomeamounts and types of the legal proceedingsinsurance commercially available to cover losses and investigations currently being conductedliabilities that might arise in connection with nuclear operations; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The licenses for our currenttwo nuclear units expire in 2042 and past business activities.  An adverse determination2044.
The NRC has broad authority under federal law to impose licensing requirements, including security, safety and employee-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, revised security or safety requirements promulgated by the NRC, particularly in response to the 2011 incident in Fukushima, Japan, could necessitate substantial capital or operating expenditures at our Susquehanna nuclear plant. There also remains substantial uncertainty regarding the temporary storage and permanent disposal of spent nuclear fuel, which could result in substantial additional costs to us that cannot be predicted. In addition, although we have no reason to anticipate a serious nuclear incident at our Susquehanna nuclear plant, if an incident did occur, any resulting operational loss, damages and injuries could have a material adverse effect on our financial condition, results of operations, cash flows and financial condition.
Our indebtedness could adversely affect our financial condition and impair our ability to operate our business.
As of December 31, 2015, we had $4,811 million in total indebtedness. Our indebtedness could have important consequences to our future financial condition, operating results and business, including the following:
requiring that a substantial portion of our cash flows from operations be dedicated to payments on our indebtedness instead of other purposes, including operations, capital expenditures and future business opportunities;
limiting our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;
increasing our cost of borrowing; and
limiting our ability to adjust to changing market and economic conditions and limiting our ability to carry out capital spending that is important to our growth.

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Although the agreements governing the Talen Energy Supply RCF contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and any additional indebtedness incurred in compliance with these restrictions could be substantial. See Note 5 to the Financial Statements for additional information regarding our indebtedness.
The agreements governing our indebtedness contain covenants that may restrict our operational flexibility.
The Talen Energy Supply RCF contains financial and other covenants that restrict our ability to, among other things:
incur additional indebtedness, or issue guarantees or certain preferred shares;
pay dividends, redeem stock or make other distributions;
repurchase, prepay or redeem subordinated indebtedness;
make investments or acquisitions;
create liens;
make negative pledges;
consolidate or merge with another company;
sell or otherwise dispose of all or substantially all of our assets; and
enter into certain transactions with affiliates.
The Amended STF Agreement and the First Lien Credit and Guaranty Agreement similarly contain customary covenants that may restrict our operational flexibility.
Our ability to borrow additional amounts under these agreements depends upon satisfaction of those covenants. Events beyond our control could affect our ability to meet those covenants. Our failure to comply with obligations under the agreements governing our indebtedness may result in an event of default under those agreements. A default, if not cured or waived, may permit acceleration of our indebtedness. If our indebtedness is accelerated, we cannot be certain that we will have sufficient funds available to pay the accelerated indebtedness or that we will have the ability to refinance the accelerated indebtedness on terms favorable to us or at all. This could have serious consequences to our financial condition, operating results and business and could cause us to become bankrupt or insolvent. See Note 5 to the Financial Statements for additional information regarding our indebtedness.
Our cash flows.

flow and ability to meet debt obligations depend on the performance of our subsidiaries and affiliates.
We are involved in legal proceedings, claimsa holding company and litigation and subject to ongoing state and federal investigations arising outconduct our operations primarily through subsidiaries. Substantially all of our business operations,consolidated assets are held by such subsidiaries. Accordingly, our cash flow and our ability to meet our obligations under certain of our debt instruments depend upon the most significantearnings of whichthese subsidiaries and the distribution or other payment of such earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. The subsidiaries are summarized in "Legal Matters," "Regulatory Issues"separate and "Environmental Matters - Domestic" in Note 15distinct legal entities and have no obligation to pay any amounts due on the notes or to make any funds available for such payment. The debt agreements of some of our subsidiaries and affiliates contain provisions that might restrict their ability to pay dividends, make distributions or otherwise transfer funds to us upon failing to meet certain financial tests or other conditions prior to the Financial Statements.  We cannot predictpayment of other obligations, including operating expenses, debt service and reserves.
Variable rate indebtedness subjects us to the ultimate outcomerisk of these matters, nor can we reasonably estimate the costs or liabilities thathigher interest rates, which could potentially result from a negative outcome in each case.cause our future debt service obligations to increase significantly.

Our borrowings under the Talen Energy Supply RCF and the First Lien Credit and Guaranty Agreement are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.
Disruption in financial markets could adversely affect our financial condition and results of operations.
Our businesses are heavily dependent on credit and access to capital, among other things, for financing capital expenditures and providing collateral to support hedging in our energy marketing business. Regulations under the Dodd-Frank Act in the United States and Basel III in Europe may impose costly additional requirements on our businesses and the businesses of others with whom we contract, such as banks or other counterparties, or simply result in increased costs to conduct our business or access sources of capital and liquidity upon which the conduct of our businesses is dependent.

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We could be negatively affected by rising interest rates, downgrades to our bond credit ratings, adverse credit market conditions or other negative developments in our ability to access capital markets.

In the ordinary course of business, we are reliant upon adequate long-term and short-term financing to fund our significant capital expenditures, debt service and operating needs. As a capital-intensive business, we are sensitive to developments in interest rate levels;rates, credit rating considerations;considerations, insurance, security or collateral requirements;requirements, market liquidity and credit availability and refinancing opportunities necessary or advisable to respond to credit market changes. Changes in these conditions as well as downgrades to our credit ratings could result in increased costs and decreased liquidityavailability of credit.
Recent or future acquisition or divestiture activities may have adverse effects on our business, financial condition and results of operations.
From time to time, we may seek to acquire additional assets or businesses. The acquisition of new assets or businesses is subject to substantial risks, including delays in completing such acquisitions, the failure to identify material problems during due diligence, the risk of over-paying for assets, the ability to retain customers or employees and the inability to arrange financing for an acquisition as may be required or desired. We may acquire assets in geographic regions or markets in which we do not currently operate, which may expose us to increased market and/or regulatory risks. In addition, we may not be able to achieve the anticipated operating and financial benefits of future acquisitions.  For example, we may not be able to achieve certain tax benefits related to our regulated utility businesses.recently completed acquisition of MACH Gen to the extent we do not have adequate taxable income in future periods following completion of the acquisition. Further, the integration and consolidation of acquired businesses requires substantial human, financial and other resources and, ultimately, such integration processes may result in unexpected costs or charges and we may not be able to operate the acquired businesses or assets in the manner in which we intended. There can be no assurances that any future acquired businesses will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.

In addition, we are required to sell certain assets pursuant to the FERC order approving the combination of Talen Energy Supply and RJS Power and we may from time to time choose to sell certain other assets or businesses that are no longer core to our operations. In connection with such dispositions, we may indemnify or guarantee counterparties against certain liabilities, which may result in future costs or liabilities payable by us. For example, we have agreed to indemnify the buyers in each of the Holtwood and Lake Wallenpaupack, Ironwood and Crane transactions against certain losses pursuant to the terms of their respective sale agreements. In addition, we may incur additional costs as a result of disposing of certain assets or businesses, and we may experience write-downs of assets if the carrying value of the assets or business sold exceeds the price received.
Changes in technology may negatively impact the value of our power plants.
A downgradebasic premise of our generation business is that generating electricity at central power plants achieves economies of scale and produces electricity at relatively low prices. There are alternate technologies to supply electricity, most notably fuel cells, micro turbines, batteries, windmills and photovoltaic (solar) cells, the development of which has expanded due to global climate change and energy efficiency concerns. Research and development activities are ongoing to seek improvements in alternate technologies. It is possible that advances will reduce the cost of alternative generation to a level that is equal to or below that of certain central station production. Also, as new technologies are developed and become available, the quantity and pattern of electricity usage (the "demand") by customers could decline, with a corresponding decline in revenues derived by generators. These alternative energy sources could result in a decline to the dispatch and capacity factors of our credit ratingsplants. As a result of all of these factors, the value of our generation facilities could negatively affectbe significantly reduced.
Our facilities may not operate as planned, which may increase our expenses and decrease our revenues and have an adverse effect on our financial performance.
Operation of our power plants, information technology systems and other assets and conduct of other activities subjects us to a variety of risks, including the breakdown or failure of equipment, accidents, security breaches, viruses or outages affecting information technology systems, labor disputes, obsolescence, delivery/ transportation problems and disruptions of fuel supply and performance below expected levels. These events may impact our ability to accessconduct our businesses efficiently and lead to increased costs, expenses or losses. Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them. Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fully in the event losses occur.

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We plan to optimize our competitive power generation operations, which involves a number of uncertainties and may not achieve the desired financial results.
We plan to optimize our competitive power generation operations. We plan to do this through the construction of new power plants or modification of existing power plants, and the potential closure of certain existing plants and acquisition of plants that may become available for sale. These types of projects involve numerous risks. Any planned power plant modifications could result in cost overruns, reduced plant efficiency and higher operating and other costs. With respect to the construction of new plants or modification of existing plants, we may be required to expend significant sums for preliminary engineering, permitting, resource exploration, legal and other expenses before it can be established whether a project is feasible, economically attractive or capable of being financed. For example, we recently committed capital to co-fire the Brunner Island coal facility on natural gas to better position the plant for low gas price environments, which is expected to be completed by the end of 2016. The success of both a new or acquired project may be contingent, among other things, upon obtaining acceptable financing and increasemaintaining acceptable credit ratings, as well as receipt of governmental approvals. If we were unable to complete construction or expansion of a project, we may not be able to recover our investment in the cost of maintaining our credit facilities andproject. Furthermore, we might be unable to operate any new debt.

Credit ratings assigned by Moody's, Fitchor modified plants as efficiently as projected, which could result in higher than projected operating and S&P to our businesses and their financial obligations have a significant impact on the cost of capital incurred by our businesses.  Although we do not expect these ratings to limit our ability to fund short-term liquidity needs or access new long-term debt, any ratings downgrade could increase our short-term borrowingother costs and negatively affect our ability to fund short-term liquidity needs and access new long-term debt.  See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Ratings Triggers" for additional information on the impact of a downgrade in our credit rating.

reduced earnings.
Significant increases in our operation and maintenance expenses, including health care and pension costs, could adversely affect our future earnings and liquidity.

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We continually focus on limiting and reducing where possible our operation and maintenance expenses. However, we expect to continue to face increased cost pressures in our operations. Increased costs of materials and labor may result from general inflation, increased regulatory requirements (especially in respect of environmental regulations), the need for higher-cost expertise in the workforce or other factors. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. We provide a similar level of benefits to our management employees. These benefits give rise to significant expenses. Due to general inflation with respect to such costs, the aging demographics of our workforce and other factors, we have experienced significant health care cost inflation in recent years, and we expect our health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take to require employees and retirees to bear a higher portion of the costs of their health care benefits. In addition, we expect to continue to incur significant costs with respect to the defined benefit pension plans for our employees and retirees. The measurement of our expected future health care and pension obligations costs and liabilitiescosts is highly dependent on a variety of assumptions, most of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, inflation rates, benefit improvements, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs and cash contribution requirements to fund these benefits could increase significantly.

We may be requiredThe loss of key personnel, the inability to record impairment charges in the future for certain of our investments, whichhire and retain qualified employees, and strikes or work stoppages by unionized employees, could adversely affect our earnings.

Under GAAP, we are required to test our recorded goodwill for impairment on an annual basis, or more frequently if events or circumstances indicate that these assets may be impaired.  Although no goodwill impairments were recorded based on our annual review in the fourth quarter of 2012, we are unable to predict whether future impairment charges may be necessary.

We also review our long-lived assets, including equity investments, for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable.  See Notes 1, 9 and 18 to the Financial Statements for additional information on impairment charges taken during the reporting periods.  We are unable to predict whether impairment charges, or other losses on sales of other assets or businesses, may occur in future years.

We may incur liabilities in connection with discontinued operations.

In connection with various divestitures, we have indemnified or guaranteed parties against certain liabilities and with respect to certain transactions.  These indemnities and guarantees relate, among other things, to liabilities which may arise with respect to the period during which we or our subsidiaries operated the divested business, and to certain ongoing contractual relationships and entitlements with respect to which we or our subsidiaries made commitments in connection with the divestiture.

We are subject to liability risks relating to our generation, transmission and distribution businesses.

The conduct of our physical and commercial operations subjects us to many risks, including risks of potential physical injury, property damage or other financial liability, caused to or by employees, customers, contractors, vendors, contractual or financial counterparties and other third parties.

Our facilities may not operate as planned, which may increase our expenses and decrease our revenues and have an adverse effect on our business, financial position and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.

Operation We cannot guarantee that any member of power plants, transmissionour management or any one of our key employees will continue to serve in any capacity for any particular period of time. Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and distribution facilities, information technology systemsincreased costs. The challenges we might face as a result of such risks include a lack of resources, losses to our knowledge base and other assetsthe time required to develop new workers' skills. In any such case, costs, including costs for contractors to replace employees, productivity costs and activities subjects ussafety costs, may rise. Failure to a variety of risks,hire and adequately train replacement employees, including the breakdowntransfer of significant internal historical knowledge and expertise to new employees, or failurechanges in the availability and cost of equipment, accidents, security breaches, viruses or outages affecting information technology systems,contract labor disputes, obsolescence, delivery/transportation problems and disruptions of fuel supply and performance below expected levels.  These events may impactadversely affect our ability to conductmanage and operate our businesses efficientlybusiness. If we are unable to successfully attract and leadretain an appropriately qualified workforce, our financial position or results of operations could be negatively affected. In addition to increased costs, expenses or losses.  Operation of our delivery systems below our expectations may result in lost revenue and increased expense, including higher maintenance costs which may not be recoverable from customers.  Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them.

Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fullyforegoing, in the event losses occur.that our union employees participate in a strike, work stoppage or engage in other forms of labor disruption, we would be responsible for procuring replacement labor and could experience reduced power generation or outages.
War, other armed conflicts or terrorist attacks, including cyber-based attacks, could have a material adverse effect on our business.
War and terrorist attacks have caused and may continue to cause instability in the world's financial and commercial markets and have contributed to high levels of volatility in prices for oil and gas. Instability and unrest in the Middle East, Afghanistan, Ukraine and Iraq, as well as threats of war or other armed conflict elsewhere, may lead to additional acts of war or terrorism, including in the United States, as well as further disruption and volatility in prices for oil and gas. Armed conflicts and terrorism and their effects on us or our markets may significantly affect our business and results of operations. In addition, we

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The operationTable of our businesses is subject to cyber-basedContents

may incur increased costs for security, including additional physical plant security and integrity risk.security personnel or additional capability following a terrorist incident.

Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems.  The operation of our generation plants, including the Susquehanna nuclear plant, and of our energy marketing and fuel trading businesses as well as our transmission and distribution operations are all reliant on cyber-based technologiescomputer systems and networks and, therefore, subject to the risk that such systems could be the target of disruptive actions, principally by terrorists, or vandals or otherwise be compromised by unintentional events.others. As a result, operations could be interrupted, property could be damaged and sensitive customer information could be lost or stolen, causing us to incur significant losses of revenues, other substantial liabilities and damages, and costs to replace or repair damaged equipment.

equipment and damage to our reputation.
We are subject to risks associated with federal and state tax laws and regulations.

Changes in tax law as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, gross receipts and franchise, sales and use, employment-related and other taxes. We also estimate our ability to utilize tax benefits and tax credits. Due to the revenue needs of the jurisdictions in which our businesses operate, various tax and fee increases may be proposed or considered. We cannot predict whether such tax legislation or regulation will be introduced or enacted or the effect of any such changes on our businesses. If enacted, any changes could increase tax expense and could have a significant negative impact on our results of operations and cash flows.

Risks Relating to or Arising out of the Talen Transactions
If the spinoff conducted as part of the Talen Transactions does not qualify as a tax-free distribution under the Code, including as a result of subsequent acquisitions of stock or equity of PPL or Talen Energy Corporation or Talen Energy Supply, then we may be liable for substantial U.S. federal income taxes or may be required to indemnify PPL.
Among other requirements, the completion of the Talen Transactions was conditioned upon PPL's receipt of a legal opinion of tax counsel to the effect that, the contribution of Talen Energy Supply to HoldCo, together with the spinoff conducted by PPL, will qualify as a reorganization pursuant to Section 368(a)(1)(D) and a tax-free distribution pursuant to Section 355 of the Code, that the merger conducted as part of those transactions will qualify as a reorganization pursuant to Section 368(a) of the Code, and that such merger and the related contribution of RJS to Talen Energy will qualify as a transaction described in Section 351 of the Code. That legal opinion is not binding on the IRS, and the IRS may reach conclusions that are different from the conclusions reached in such opinion. We are not aware of any facts or circumstances that would cause the factual statements or representations on which the legal opinion was based to be materially different from the facts at the time the Talen Transactions were completed. If, notwithstanding the receipt of such opinion, the IRS were to determine the spinoff to be taxable, PPL would recognize a tax liability that could be substantial. We would be jointly and severally liable for such tax liability under applicable Treasury Regulations as a former member of the PPL consolidated federal income tax group.
In addition, the spinoff will be taxable to PPL pursuant to Section 355(e) of the Code if there is a 50% or greater change in ownership (by vote or value) of PPL, Talen Energy Corporation or Talen Energy Supply, directly or indirectly, as part of a plan or series of related transactions that include the spinoff. Because PPL's shareholders collectively owned more than 50% of Talen Energy Corporation's common stock following the Talen Transactions, the Talen Transactions alone will not cause the spinoff to be taxable to PPL under Section 355(e) of the Code. However, Section 355(e) of the Code might apply if acquisitions of stock of PPL before or after the spinoff, or stock or equity of Talen Energy Corporation or Talen Energy Supply after June 1, 2015, are considered to be part of a plan or series of related transactions that include the spinoff. We are not aware of any such plan or series of transactions. Under the separation agreement, however, in certain circumstances and subject to certain limitations, we would be required to indemnify PPL for certain taxes that may be imposed on the spinoff, including taxes that arise because acquisitions of Talen Energy Corporation stock or Talen Energy Supply equity result in the Talen Energy spinoff being taxable under Section 355(e) of the Code.
We are subjectmay not realize the anticipated synergies, cost savings and growth opportunities from the Talen Transactions.
The benefits that we expect to achieve as a result of the riskTalen Transactions will depend, in part, on our ability to realize anticipated growth opportunities, cost savings and other synergies. Our success depends on the continued integration of the Talen Energy and RJS Power businesses, which could result in significant expenses that our workforce and its knowledge base may become depleted in coming years.

PPL is experiencing an increase in attrition due primarily to the number of retiring employees.  Over the period from 2014 through 2018, 23.5% of PPL's total workforce is projected to leave the company, with the risk that critical knowledge will be lost and that it may be difficult to replace departed personnel dueestimate accurately at this time. In addition, we may experience challenges when combining separate business cultures, information technology systems and employees, and those challenges may divert senior management's time and attention. Even if we are able to a declining trend incomplete the number of available skilled workers and an increase in competition for such workers.

(PPL, PPL Energy Supply and LKE)

Risk Related to Registrant Holding Companies

PPL's, PPL Energy Supply's and LKE's cash flows and ability to meet their obligations with respect to indebtedness and under guarantees, and PPL's ability to pay dividends, largely depends on the financial performance of their subsidiaries and, as a result, is effectively subordinated to all existing and future liabilities of those subsidiaries.
PPL, PPL Energy Supply and LKE are holding companies and conduct their operations primarily through subsidiaries.  Substantiallyintegration successfully, we may not fully realize all of the consolidated assets of these Registrants are held by such subsidiaries.  Accordingly, their cash flows and ability to meet their debt and guaranty obligations, as well as PPL's ability to pay dividends, are largely dependent upon the earnings of those subsidiaries and the distribution or other payment of such earnings in the form of dividends, distributions, loans or advances or repayment of loans and advances.  The subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts due from their parents or to make any funds available for such a payment.  The ability of the subsidiaries of the Registrants to pay dividends or distributions to such Registrants in the future will depend on the subsidiaries' future earnings and cash flows and the needs of their businesses, and may be restricted by their obligations to holders of their outstanding debt and other creditors, as well as any contractual or legal restrictions in effect at such time, including the requirements of state corporate law applicable to payment of dividends and distributions, and regulatory requirements, including restrictions on the ability of PPL Electric, LG&E and KU to pay dividends under Section 305(a) of the Federal Power Act.
Because PPL, PPL Energy Supply and LKE are holding companies, their debt and guaranty obligations are effectively subordinated to all existing and future liabilities of their subsidiaries.  Therefore, PPL's, PPL Energy Supply's and LKE's rights and the rights of their creditors, including rights of any debt holders, to participate in the assets of any of their subsidiaries, in the event that such a subsidiary is liquidated or reorganized, will be subject to the prior claims of such subsidiary's creditors.  Although certain agreements to which certain subsidiaries are parties limit their ability to incur additional indebtedness, PPL, PPL Energy Supply and LKE and their subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities. In addition, if PPL elects to receive distributions of earnings from its foreign operations, PPL may incur U.S. income taxes, net of any available foreign tax credits, on such amounts.
25

(PPL, PPL Electric, LKE, LG&E and KU)

Risks Related to Domestic Regulated Utility Operations

Our domestic regulated utility businesses face many of the same risks, in addition to those risks that are unique to the Kentucky Regulated segment and the Pennsylvania Regulated segment.  Set forth below are risk factors common to both domestic regulated segments, followed by sections identifying separately the risks specific to each of these segments.

Our profitability is highly dependent on our ability to recover the costs of providing energy and utility services to our customers and earn an adequate return on our capital investments.  Regulators may not approve the rates we request.

We currently provide services to our utility customers at rates approved by one or more federal or state regulatory commissions, including those commissions referred to below.  While such regulation is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, the rates that we may charge our regulated generation, transmission and distribution customers are subject to authorization of the applicable regulatory authorities.  There can be no assurance that such regulatory authorities will consider all of our costs to have been prudently incurred or that the regulatory process by which rates are determined will always result in rates that achieve full recovery of our costs or an adequate return on our capital investments.  While our rates are generally regulated based on an analysis of our costs incurred in a base year or based on future projected costs, the rates we are allowed to charge may or may not match our costs at any given time.  Our regulated utility businesses are subject to substantial capital expenditure requirements over the next several years, which will likely require rate increase requests to the regulators.  If our costs are not adequately recovered through rates, it could have an adverse effect on our business, results of operations, cash flows and financial condition.

Our domestic utility businesses are subject to significant and complex governmental regulation.

Various federal and state entities, including but not limited to the FERC, KPSC, VSCC, TRA and PUC regulate many aspects of the domestic utility operations of PPL, including:

·the rates that we may charge and the terms and conditions of our service and operations;
·financial and capital structure matters;
·siting, construction and operation of facilities;
·mandatory reliability and safety standards and other standards of conduct;
·accounting, depreciation and cost allocation methodologies;
·tax matters;
·affiliate restrictions;
·acquisition and disposal of utility assets and securities; and
·various other matters.

Such regulations or changes thereto may subject us to higher operating costs or increased capital expenditures and failure to comply could result in sanctions or possible penalties.  In any rate-setting proceedings, federal or state agencies, intervenors and other permitted parties may challenge our rate requests, and ultimately reduce, alter or limit the rates we seek.

We could be subject to higher costs and/or penalties related to mandatory reliability standards.

Under the Energy Policy Act of 2005, owners and operators of the bulk power electricity system are now subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC.  Compliance with reliability standards may subject us to higher operating costs and/or increased capital expenditures, and violations of these standards could result in substantial penalties which may not be recoverable from customers.

Changes in transmission and wholesale power market structures could increase costs or reduce revenues.

Wholesale revenues fluctuate with regional demand, fuel prices and contracted capacity.  Changes to transmission and wholesale power market structures and prices may occur in the future, are not predictable and may result in unforeseen effects on energy purchases and sales, transmission and related costs or revenues.  These can include commercial or regulatory changes affecting power pools, exchanges or markets in which PPL participates.

Our domestic regulated businesses undertake significant capital projects and these activities are subject to unforeseen costs, delays or failures, as well as risk of inadequate recovery of resulting costs.

26

The domestic regulated utility businesses are capital intensive and require significant investments in energy generation (in the case of LG&E and KU) and transmission, distribution and other infrastructure projects, such as projects for environmental compliance and system reliability.  The completion of these projects without delays or cost overruns is subject to risks in many areas, including:

·approval, licensing and permitting;
·land acquisition and the availability of suitable land;
·skilled labor or equipment shortages;
·construction problems or delays, including disputes with third party intervenors;
·increases in commodity prices or labor rates;
·contractor performance;
·environmental considerations and regulations;
·weather and geological issues; and
·political, labor and regulatory developments.

Failure to complete our capital projects on schedule or on budget, or at all, could adversely affect our financial performance, operations and future growth if such expenditures are not granted rate recovery by our regulators.

Risks Specific to Kentucky Regulated Segment

(PPL, LKE, LG&E and KU)

The costs of compliance with, and liabilities under, environmental laws are significant and are subject to continuing changes.

Extensive federal, state and local environmental laws and regulations are applicable to LG&E's and KU's generation business, including its air emissions, water discharges and the management of hazardous and solid waste, among other business-related activities; and the costs of compliance or alleged non-compliance cannot be predicted but could be material.  In addition, our costs may increase significantly if the requirements or scope of environmental laws, regulations or similar rules are expanded or changed.  Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or forfeitures or other restrictions.  Many of these environmental law considerations are also applicable to the operations of our key suppliers, or customers, such as coal producers and industrial power users, and may impact the costs of their products and demand for our services.

Ongoing changes in environmental regulations or their implementation requirements and our compliance strategies relating thereto entail a number of uncertainties.

The environmental standards governing LG&E's and KU's businesses, particularly as applicable to coal-fired generation and related activities, continue to be subject to uncertainties due to ongoing rulemakings and other regulatory developments, legislative activities and litigation.  The uncertainties associated with these developments introduce risks to our management of operations and regulatory compliance.  Environmental developments, including revisions to applicable standards, changes in compliance deadlines and invalidation of rules on appeal may require major changes in compliance strategies, operations or assets and adjustments to prior plans.  Depending on the extent, frequency and timing of such changes, the companies may be subject to inconsistent requirements under multiple regulatory programs, compressed windows for decision-making and short compliance deadlines that may require aggressive schedules for construction, permitting, and other regulatory approvals.  Under such circumstances, the companies may face higher risks of unsuccessful implementation of environmental-related business plans, noncompliance with applicable environmental rules, or increased costs of implementation.

Risks Specific to Pennsylvania Regulated Segment

(PPL and PPL Electric)

We may be subject to higher transmission costs and other risks as a result of PJM's regional transmission expansion plan (RTEP) process.
27

PJM and the FERC have the authority to require upgrades or expansion of the regional transmission grid, which can result in substantial expenditures for transmission owners.  As discussed in Note 8 to the Financial Statements, we expect to make substantial expenditures to construct the Susquehanna-Roseland transmission line that PJM has determined is necessary for the reliability of the regional transmission grid.  Although the FERC has granted our request for incentive rate treatment of such facilities, we cannot be certain that all costs that we may incur will be recoverable.  In addition, the date when these facilities will be in service, which can be significantly impacted by delays related to public opposition or other factors, is subject to the outcome of future events that are not all within our control.  As a result, we cannot predict the ultimate financial or operational impact of this project or other RTEP projects on PPL Electric.

We could be subject to higher costs and/or penalties related to Pennsylvania Conservation and Energy Efficiency Programs.

PPL Electric is subject to Act 129 which contains requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposes new PLR electricity supply procurement rules, provides remedies for market misconduct, and made changes to the existing AEPS.  The law also requires electric utilities to meet specified goals for reduction in customer electricity usage and peak demand by specified dates (2011 and 2013 for Phase 1 and by 2016 for Phase 2).  Utilities not meeting these requirements of Act 129 are subject to significant penalties that cannot be recovered in rates.  Numerous factors outside of our control could prevent compliance with these requirements and result in penalties to us.

(PPL)

Risks Related to U.K. Regulated Segment

Our U.K. delivery business is subject to risks with respect to rate regulation and operational performance.

Our U.K. delivery business is rate-regulated and operates under an incentive-based regulatory framework.  In addition, its ability to manage operational risk is critical to its financial performance.  Disruption to the distribution network could reduce profitability both directly through the higher costs for network restoration and also through the system of penalties and rewards that Ofgem has in place relating to customer service levels.

In December 2009, Ofgem completed its rate review for the five-year period from April 1, 2010 through March 31, 2015, reducing regulatory rate uncertainty in the U.K. Regulated segment until the next rate review which will be effective April 1, 2015.  The regulated income of the U.K. Regulated segment and also the RAV are to some extent linked to movements in the Retail Price Index (RPI), a measure of inflation.  Reductions in the RPI would adversely impact revenues and the debt-to-RAV ratio.

Our U.K. distribution business exposes us to risks related to U.K. laws and regulations, taxes, economic conditions, foreign currency exchange rate fluctuations, and political conditions and policies of the U.K. government.  These risks may reduce the results of operations from our U.K. distribution business:

·changes in laws or regulations relating to U.K. operations, including tax laws and regulations;
·changes in government policies, personnel or approval requirements;
·changes in general economic conditions affecting the U.K.;
·regulatory reviews of tariffs for distribution companies;
·severe weather and natural disaster impacts on the electric sector and our assets;
·changes in labor relations;
·limitations on foreign investment or ownership of projects and returns or distributions to foreign investors;
·limitations on the ability of foreign companies to borrow money from foreign lenders and lack of local capital or loans;
·fluctuations in foreign currency exchange rates and in converting U.K. revenues to U.S. dollars, which can increase our expenses and/or impair our ability to meet such expenses, and difficulty moving funds out of the country in which the funds were earned; and
·compliance with U.S. foreign corrupt practices laws.
The WPD Midlands acquisition may not achieve its intended results, including anticipated cost savings, efficiencies and other benefits.
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Although we completed the WPD Midlands acquisition with the expectation that it will result in various benefits, including a significant amount ofopportunities, cost savings and other synergies that we expect, either within the anticipated time frame for integration or at all. For example, we may be unable to eliminate all duplicative costs. Also, as a standalone company outside of the PPL and Riverstone groups of companies, we may not be able to replace the resources provided by PPL or Riverstone to the Talen Energy and RJS Power businesses prior to the Talen

26

Transactions. Alternatively, we may be able to replace them but not at the same or lower cost as what previously was available, and any resulting incremental costs could be material.
Our accounting, management and financial reporting systems may not be adequately prepared to comply with the disclosure controls and operational benefits, there can be no assurance regarding the extentinternal control over financial reporting requirements to which we will be ableare subject.
Prior to realize these cost-savings or other benefits.  AchievingJune 1, 2015, our financial results were included within the anticipated benefits, including cost savings, isconsolidated results of PPL, and RJS Power was not subject to a numberthe reporting and other requirements of uncertainties, including whether the businesses acquired can be operated in the manner we intend.  Events outside of our control, including but not limited to regulatory changes or developments in the U.K., could also adversely affect our ability to realize the anticipated benefits from the WPD Midlands acquisition.Exchange Act.
The WPD Midlands acquisition exposes us to additional risks and uncertainties with respect to the acquired businesses and their operations.
Although the WPD Midlands acquisition increased our relative investment in regulated operations, which we believe should help mitigate our exposure to downturns in the wholesale power markets, it will increase our dependence on rate-of-return regulation.  

The WPD businesses generallyWe now are subject to risks similar to those toreporting and other obligations under the Exchange Act and are responsible for ensuring that all aspects of our business comply with Section 404 of the Sarbanes-Oxley Act, under which we were subject in our pre-acquisition U.K. businesses.  These include:
·There are various changes being contemplated by Ofgem to the current electricity distribution, gas transmission and gas distribution regulatory frameworks in the U.K. and there can be no assurance as to the effects such changes will have on our U.K. regulated businesses in the future, including the acquired businesses.  In particular, in October 2010, Ofgem announced a new regulatory framework that is expected to become effective in April 2015 for the electricity distribution sector in the U.K.  The framework, known as RIIO (Revenues = Incentives + Innovation + Outputs), focuses on sustainability, environmental-focused output measures, promotion of low carbon energy networks and financing of new investments.  The new regulatory framework is expected to have a wide-ranging effect on electricity distribution companies operating in the U.K., including changes to price controls and price review periods.  Our U.K. regulated businesses' compliance with this new regulatory framework may result in significant additional capital expenditures, increases in operating and compliance costs and adjustments to our pricing models.
·Ofgem has formal powers to propose modifications to each distribution license.  We are not currently aware of any planned modification to any of our U.K. regulated businesses distribution licenses that would result in a material adverse change to the U.K. regulated businesses and PPL.  There can, however, be no assurance that a restrictive modification will not be introduced in the future, which could have an adverse effect on the operations and financial condition of the U.K. regulated businesses and PPL.
·A failure to operate our U.K. networks properly could lead to compensation payments or penalties, or a failure to make capital expenditures in line with agreed investment programs could lead to deterioration of the network.  While our U.K. regulated businesses' investment programs are targeted to maintain asset conditions over a five-year period and reduce customer interruptions and customer minutes lost over that period, no assurance can be provided that these regulatory requirements will be met.
·A failure by any of our U.K. regulated businesses to comply with the terms of a distribution license may lead to the issuance of an enforcement order by Ofgem that could have an adverse impact on PPL.  Ofgem has powers to levy fines of up to 10 percent of revenue for any breach of a distribution license or, in certain circumstances, such as insolvency, the distribution license itself may be revoked.  Unless terminated in the circumstances mentioned above, a distribution license continues indefinitely until revoked by Ofgem following no less than 25 years' written notice.
·We will be subject to increased foreign currency exchange rate risks because a greater portion of our cash flows and reported earnings will be generated by our U.K. business operations.  These risks relate primarily to changes in the relative value of the British pound sterling and the U.S. dollar between the time we initially invest U.S. dollars in our U.K. businesses and the time that cash is repatriated to the U.S.must maintain effective disclosure controls and procedures and internal control over financial reporting. To comply with these requirements on a stand-alone basis separate from the U.K., including cash flows from our U.K. businesses that may be distributed as future dividends to our shareholders or repayments of intercompany loans.  In addition, our consolidated reported earnings on a U.S. GAAP basis may be subject to increased earnings translation risk, which is the result of the conversion of earnings as reported in our U.K. businesses on a British pound sterling basis to a U.S. dollar basis in accordance with U.S. GAAP requirements.
·Environmental costs and liabilities associated with aspects of the acquired businesses may differ from those of our existing business.
29
Risks Related to Supply Segment

(PPL and PPL Energy Supply)

We face intense competition inwith the addition of the RJS Power business, we may need to upgrade our energy supply business, which may adversely affectsystems, implement additional financial and management controls, reporting systems and procedures, and hire additional accounting, legal and finance staff. Along those lines, our ability to operate profitably.

Unlike our regulated utility businesses, our energy supply business is dependentreport on our abilityinternal control over financial reporting in this Form 10-K includes a scope exception for the RJS Power business. It also includes a scope exception for the MACH Gen business acquired in November 2015. We expect to operate in a competitive environmentincur additional annual expenses for the purpose of addressing these reporting and is not assured of any rate of return on capital investments through a predetermined rate structure.  Competition is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors.  These competitive factors may negatively impact our ability to sell electricity and related products and services, as well as the prices that we may charge for such products and services, which could adversely affect our results of operations and our ability to grow our business.

We sell our available energy and capacity into the competitive wholesale markets through contracts of varying duration.  Competition in the wholesale power markets occurs principally on the basis of the price of products and, to a lesser extent, on the basis of reliability and availability.  We believe that the commencement of commercial operation of new electricity generating facilities in the regional markets where we own or control generation capacity and the evolution of demand side management resources will continue to increase competition in the wholesale electricity market in those regions, which could have an adverse effect on capacity prices and the prices we receive for electricity.

We also face competition in the wholesale markets for electricity capacity and ancillary services.  We primarily compete with other electricity suppliers based on our ability to aggregate supplies at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities and ISOs.  We also compete against other energy marketers on the basis of relative financial condition and access to credit sources, and our competitors may have greater financial resources than we have.

Competitors in the wholesale power markets in which PPL Generation subsidiaries and PPL EnergyPlus operate include regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities and financial institutions.

Adverse changes in commodity prices and related costs may decrease our future energy margins, which could adversely affect our earnings and cash flows.

Our energy margins, or the amount by which our revenues from the sale of power exceed our costs to supply power, are impacted by changes in market prices for electricity, fuel, fuel transportation, emission allowances, RECs, electricity transmission and related congestion charges and other costs.  Unlike most commodities, the limited ability to store electric power requires that it must be consumed at the time of production.  As a result, wholesale market prices for electricity may fluctuate substantially over relatively short periods of time and can be unpredictable.  Among the factors that influence such prices are:
·demand for electricity;
·supply and demand for electricity available from current or new generation resources;
·variable production costs, primarily fuel (and the associated fuel transportation costs) and emission allowance expense for the generation resources used to meet the demand for electricity;
·transmission capacity and service into, or out of, markets served;
·changes in the regulatory framework for wholesale power markets;
·liquidity in the wholesale electricity market, as well as general creditworthiness of key participants in the market; and
·weather and economic conditions impacting demand for or the price of electricity or the facilities necessary to deliver electricity.
We do not always hedge against risks associated with electricity and fuel price volatility.

We attempt to mitigate risks associated with satisfying our contractual electricity sales obligations by either reserving generation capacity to deliver electricity or purchasing the necessary financial or physical products and services through competitive markets to satisfy our net firm sales contracts.  We also routinely enter into contracts, such as fuel and electricity purchase and sale commitments, to hedge our exposure to fuelcompliance requirements, and other electricity-related commodities.  However, based on economic and other considerations, we may decide not to hedge the entire exposure of our operations from commodity price risk.  To the extent we do not hedge against commodity price risk, our results of operations and financial positionthose expenses may be adversely affected.

30
We are exposed to operational, price and credit risks associated with selling and marketing products in the wholesale and retail electricity markets.

We purchase and sell electricity in wholesale markets under market-based tariffs authorized by FERC throughout the U.S. and also enter into short-term agreements to market available electricity and capacity from our generation assets with the expectation of profiting from market price fluctuations.significant. If we are unable to deliver firm capacityupgrade our financial and electricity under these agreements, we could be required to pay damages.  These damages would generally be based on the difference between the market price to acquire replacement capacity or electricitymanagement controls, reporting systems, IT systems and the contract price of any undelivered capacity or electricity.  Depending on price volatilityprocedures in the wholesale electricity markets, such damages could be significant.  Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions,a timely and other factors could affecteffective fashion, our ability to meet our obligations, or cause significant increases insatisfy financial reporting requirements and other rules that apply to reporting companies under the market price of replacement capacityExchange Act and electricity.

Our wholesale power agreements typically include provisions requiring us to post collateral for the benefit of our counterparties if the market price of energy varies from the contract prices in excess of certain pre-determined amounts.  We currently believe that we have sufficient credit to fulfill our potential collateral obligations under these power contracts.  However, our obligation to post collateral could exceed the amount of our facilities or our ability to increase our facilitiesSarbanes-Oxley Act could be limited by financial markets or other factors.  See Note 7impaired. Any failure to the Financial Statements for a discussion of PPL's credit facilities.

We also face credit risk that parties with whom we contract in both the wholesaleachieve and retail markets will default in their performance, in which case we may have to sell our electricity into a lower-priced market or make purchases in a higher-priced market than existed at the time of contract.  Whenever feasible, we attempt to mitigate these risks using various means, including agreements that require our counterparties to post collateral for our benefit if the market price of energy varies from the contract price in excess of certain pre-determined amounts.  However, there can be no assurance that we will avoid counterparty nonperformance risk, including bankruptcy, which could adversely impact our ability to meet our obligations to other parties, which could in turn subject us to claims for damages.

The load following contracts that PPL EnergyPlus is awarded do not provide for specific levels of load and actual load significantly below or above our forecasts could adversely affect our energy margins.

We generally hedge our load following obligations with energy purchases from third parties, and to a lesser extent with our own generation.  If the actual load is significantly lower than the expected load, we may be required to resell power at a lower price than was contracted for to supply the load obligation, resulting in a financial loss.  Alternatively, a significant increase in load could adversely affect our energy margins because we are required under the terms of the load following contracts to provide the energy necessary to fulfill increased demand at the contract price, which could be lower than the cost to procure additional energy on the open market.  Therefore, any significant decrease or increase in load compared with our forecastsmaintain effective internal controls could have a material adverse effect on our business, financial condition and results of operationsoperations.
Ownership of our common stock is highly concentrated, and financial position.the Riverstone Holders may exert significant influence over matters requiring Board of Directors and/or stockholder approval.

We may experience disruptions inThe Riverstone Holders, each of which is indirectly controlled by Riverstone, collectively beneficially own approximately 35% of the outstanding shares of our fuel supply, which could adversely affect ourcommon stock. As a result, the Riverstone Holders collectively exercise significant influence over all matters requiring stockholder approval for the foreseeable future, including approval of significant corporate transactions. Moreover, pursuant to a stockholder agreement, the Riverstone Holders have the right to appoint individuals to serve on the Board of Directors of Talen Energy Corporation. See "Item 13. Certain Relationships and Related Transactions, and Director Independence." Currently, Messrs. Alexander, Casey and Hoffman serve on the Board of Directors as designees of the Riverstone Holders. As a result, the Riverstone Holders have the ability to operateexert significance influence over matters requiring approval of our generation facilities.Board of Directors and other matters subject to the terms of that stockholder agreement.

We purchase fuel fromThe interests of the Riverstone Holders may conflict with the interests of our other stockholders. The Riverstone Holders may have an interest in having us pursue acquisitions, divestitures and other transactions that, in their judgment, could enhance their investment in us, even though such transactions might involve risks to other stockholders. In addition, Riverstone and its affiliates engage in a broad spectrum of activities, including investments in the power generation industry. In the ordinary course of their business activities, Riverstone and its affiliates may engage in activities where their interests conflict with our interests or those of our stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Talen Energy Corporation and Talen Energy Supply, LLC

None.

27

ITEM 2. PROPERTIES

The capacity of generation units is based on a number of suppliers.  Disruption infactors, including the deliveryoperating experience and physical conditions of fuelthe units and other products consumed during the production of electricity (suchmay be revised periodically to reflect changed circumstances. Talen Energy's electric generating capacity (summer rating) at December 31, 2015 by segment was as coal, natural gas, oil, water, uranium, lime, limestone and other chemicals), including disruptions as a result of weather, transportation difficulties, global demand and supply dynamics, labor relations, environmental regulations or the financial viability of our fuel suppliers, could adversely affect our ability to operate our facilities, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations.follows.
Plant Owner Total MW Capacity % Ownership Talen Energy's Ownership in MW Fuel Type State Region/ISO
               
East segment              
Martins Creek Talen Generation 1,708
 100.00 1,708
 Natural Gas/Oil PA PJM
Ironwood (a) Talen Generation 661
 100.00 661
 Natural Gas PA PJM
Lower Mt. Bethel Talen Generation 555
 100.00 555
 Natural Gas PA PJM
Combustion turbines Talen Generation 370
 100.00 370
 Natural Gas/Oil PA PJM
Bayonne Sapphire 165
 100.00 165
 Natural Gas/Oil NJ PJM
Camden Sapphire 145
 100.00 145
 Natural Gas/Oil NJ PJM
Dartmouth Sapphire 82
 100.00 82
 Natural Gas/Oil MA ISO-NE
Elmwood Park Sapphire 70
 100.00 70
 Natural Gas/Oil NJ PJM
Newark Bay Sapphire 122
 100.00 122
 Natural Gas/Oil NJ PJM
Pedricktown (b) Sapphire 117
 100.00 117
 Natural Gas/Oil NJ PJM
York Sapphire 46
 100.00 46
 Natural Gas PA PJM
Montour Talen Generation 1,528
 100.00 1,528
 Coal PA PJM
Brunner Island Talen Generation 1,428
 100.00 1,428
 Coal PA PJM
Keystone (c) Talen Generation 1,718
 12.34 212
 Coal PA PJM
Conemaugh (c) Talen Generation 1,754
 16.25 285
 Coal PA PJM
Brandon Shores Raven 1,274
 100.00 1,274
 Coal MD PJM
C.P. Crane (a) Raven 402
 100.00 402
 Coal MD PJM
H.A. Wagner Raven 966
 100.00 966
 Coal/Natural Gas/Oil MD PJM
Susquehanna (c) Talen Generation 2,513
 90.00 2,262
 Nuclear PA PJM
Holtwood (a) Talen Generation 262
 100.00 262
 Hydro PA PJM
Lake Wallenpaupack (a) Talen Generation 46
 100.00 46
 Hydro PA PJM
Athens MACH Gen 969
 100.00 969
 Natural Gas NY NYISO
Millennium MACH Gen 335
 100.00 335
 Natural Gas MA ISO-NE
Renewables (d) N/A 7
 100.00 7
 Renewables PA PJM
    17,243
   14,017
      
West segment              
Laredo Jade 181
 100.00 181
 Natural Gas TX ERCOT
Nueces Bay Jade 648
 100.00 648
 Natural Gas TX ERCOT
Barney Davis Jade 964
 100.00 964
 Natural Gas TX ERCOT
Harquahala MACH Gen 1,040
 100.00 1,040
 Natural Gas AZ WECC
Colstrip Units 1 & 2 (c) Talen Generation 614
 50.00 307
 Coal MT WECC
Colstip Unit 3 (c) Talen Generation 740
 30.00 222
 Coal MT WECC
    4,187
   3,362
      
Total   21,430
   17,379
      

Unforeseen changes in the price of coal and natural gas could cause us to incur excess coal inventories and contract termination costs.

Extraordinarily low natural gas prices during 2012 caused natural gas to be the more cost competitive fuel compared to coal for generating electricity.  Because we enter into guaranteed supply contracts to provide for the amount of coal needed to operate our base load coal-fired generating facilities, we may experience periods where we hold excess amounts of coal if fuel pricing results in our reducing or idling coal-fired generating facilities in favor of operating available alternative natural gas-fired generating facilities.  In addition, we may incur costs to terminate supply contracts for coal in excess of our generating requirements.

Our risk management policy and programs relating to electricity and fuel prices, interest rates and counterparty credit and non-performance risks may not work as planned, and we may suffer economic losses despite such programs.

31
We actively manage the market risk inherent in our generation and energy marketing activities, as well as our debt and counterparty credit positions.  We have implemented procedures to monitor compliance with our risk management policy and programs, including independent validation of transaction and market prices, verification of risk and transaction limits, portfolio stress tests, sensitivity analyses and daily portfolio reporting of various risk management metrics.  Nonetheless, our risk management programs may not work as planned.  For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which we based our risk management calculations.  Additionally, unforeseen market disruptions could decrease market depth and liquidity, negatively impacting our ability to enter into new transactions.  We enter into financial contracts to hedge commodity basis risk, and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery.  Similarly, interest rates or foreign currency exchange rates could change in significant ways that our risk management procedures were not designed to address.  As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position.

In addition, our trading, marketing and hedging activities are exposed to counterparty credit risk and market liquidity risk.  We have adopted a credit risk management policy and program to evaluate counterparty credit risk.  However, if counterparties fail to perform, we may be forced to enter into alternative arrangements at then-current market prices.  In that event, our financial results are likely to be adversely affected.

Our costs to comply with existing and new environmental laws are expected to continue to be significant, and we plan to incur significant capital expenditures for pollution control improvements that, if delayed, would adversely affect our profitability and liquidity.

Our business is subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection.  To comply with existing and future environmental requirements and as a result of voluntary pollution control measures we may take, we have spent and expect to spend substantial amounts in the future on environmental control and compliance.

In order to comply with existing and previously proposed federal and state environmental laws and regulations primarily governing air emissions from coal-fired plants, since 2005 PPL has spent more than $1.6 billion to install scrubbers and other pollution control equipment (primarily aimed at sulfur dioxide, particulate matter and nitrogen oxides with co-benefits for mercury emissions reduction) in its competitive generation fleet.  Many states and environmental groups have challenged certain federal laws and regulations relating to air emissions as not being sufficiently strict.  As a result, state and federal regulations have been adopted that would impose more stringent restrictions than are currently in effect, which could require us significantly to increase capital expenditures for additional pollution control equipment.

We may not be able to obtain or maintain all environmental regulatory approvals necessary for our planned capital projects which are necessary to our business.  If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted, reduced or subjected to additional costs.  Furthermore, at some of our older generating facilities it may be uneconomic for us to install necessary pollution control equipment, which could cause us to retire those units.

For more information regarding environmental matters, including existing and proposed federal, state and local statutes, rules and regulations to which we are subject, see "Environmental Matters - Domestic" in Note 15 to the Financial Statements.

We rely on transmission and distribution assets that we do not own or control to deliver our wholesale electricity.  If transmission is disrupted, or not operated efficiently, or if capacity is inadequate, our ability to sell and deliver power may be hindered.

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell in the wholesale market, as well as the natural gas we purchase for use in our electricity generation facilities.  If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs and RTOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products at the most favorable terms.

The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis.  Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission capacity will not be available in the amounts we require.  We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs and RTOs in applicable markets will efficiently operate transmission networks and provide related services.

32



Despite federal and state deregulation initiatives, our supply business is still subject to extensive regulation, which may increase our costs, reduce our revenues, or prevent or delay operation of our facilities.

Our generation subsidiaries sell electricity into the wholesale market.  Generally, our generation subsidiaries and our marketing subsidiaries are subject to regulation by the FERC.  The FERC has authorized us to sell generation from our facilities and power from our marketing subsidiaries at market-based prices.  The FERC retains the authority to modify or withdraw our market-based rate authority and to impose "cost of service" rates if it determines that the market is not competitive, that we possess market power or that we are not charging just and reasonable rates.  Any reduction by the FERC in the rates we may receive or any unfavorable regulation of our business by state regulators could materially adversely affect our results of operations.  See "FERC Market-Based Rate Authority" in Note 15 to the Financial Statements for information regarding recent court decisions that could impact the FERC's market-based rate authority program.

In addition, the acquisition, construction, ownership and operation of electricity generation facilities require numerous permits, approvals, licenses and certificates from federal, state and local governmental agencies.  We may not be able to obtain or maintain all required regulatory approvals.  If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approval or fail to comply with any applicable law or regulation, the operation of our assets and our sales of electricity could be prevented or delayed or become subject to additional costs.

If market deregulation is reversed or discontinued, our business prospects and financial condition could be materially adversely affected.

In some markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-based pricing, re-regulate areas of these markets that have previously been competitive or permit electricity delivery companies to construct, contract for, or acquire generating facilities.  The ISOs that oversee the transmission systems in certain wholesale electricity markets have from time to time been authorized to impose price limitations and other mechanisms to address extremely high prices in the power markets.  These types of price limitations and other mechanisms may reduce profits that our wholesale power marketing and trading business would have realized under competitive market conditions absent such limitations and mechanisms.  Although we generally expect electricity markets to continue to be competitive, other proposals to re-regulate our industry may be made, and legislative or other actions affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in states in which we currently, or may in the future, operate.  See "New Jersey Capacity Legislation" and "Maryland Capacity Order" in Note 15 to the Financial Statements.

Changes in technology may negatively impact the value of our power plants.

A basic premise of our generation business is that generating electricity at central power plants achieves economies of scale and produces electricity at relatively low prices.  There are alternate technologies to produce electricity, most notably fuel cells, micro turbines, windmills and photovoltaic (solar) cells, the development of which has been expanded due to global climate change concerns.  Research and development activities are ongoing to seek improvements in alternate technologies.  It is possible that advances will reduce the cost of alternate methods of electricity production to a level that is equal to or below that of certain central station production.  Also, as new technologies are developed and become available, the quantity and pattern of electricity usage (the "demand") by customers could decline, with a corresponding decline in revenues derived by generators.  These alternative energy sources could result in a decline to the dispatch and capacity factors of our plants.  As a result of all of these factors, the value of our generation facilities could be significantly reduced.

We are subject to certain risks associated with nuclear generation, including the risk that our Susquehanna nuclear plant could become subject to increased security or safety requirements that would increase capital and operating expenditures, uncertainties regarding spent nuclear fuel, and uncertainties associated with decommissioning our plant at the end of its licensed life.

Nuclear generation accounted for about 31% of our 2012 generation output.  The risks of nuclear generation generally include:

·
(a)Plant was sold in the potential harmful effects onfirst quarter of 2016 or is under an agreement of sale to satisfy the environment and human health from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
·limitations on the amounts and types of insurance commercially available to cover losses and liabilities that might ariseFERC approved mitigation in connection with nuclear operations; and
·uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.  The licenses for our two nuclear units expire in 2042 and 2044.RJS Power acquisition. See Note 211 to the Financial Statements for additional information on the ARO related to the decommissioning.

33
The NRC has broad authority under federal law to impose licensing requirements, including security, safety and employee-related requirements for the operation of nuclear generation facilities.  In the event of noncompliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  In addition, revised security or safety requirements promulgated by the NRC could necessitate substantial capital or operating expenditures at our Susquehanna nuclear plant.  There also remains substantial uncertainty regarding the temporary storage and permanent disposal of spent nuclear fuel, which could result in substantial additional costs to PPL that cannot be predicted.  In addition, although we have no reason to anticipate a serious nuclear incident at our Susquehanna plant, if an incident did occur, any resulting operational loss, damages and injuries could have a material adverse effect on our results of operations, cash flows and financial condition.  See Note 15 to the Financial Statements for a discussion of nuclear insurance.

ITEM 1B. UNRESOLVED STAFF COMMENTS

PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

None.

34

ITEM 2. PROPERTIES

(PPL, LKE, LG&E and KU)

Kentucky Regulated Segment

LG&E's and KU's properties consist primarily of regulated generation facilities, electric transmission and distribution assets and natural gas transmission and distribution assets in Kentucky.  The electric generating capacity at December 31, 2012 was:

     LKE LG&E KU
              
   Total MW Ownership or   Ownership or   Ownership or
   Capacity (b) Lease Interest   Lease Interest   Lease Interest
Primary Fuel/Plant (a) Summer in MW % Ownership in MW % Ownership in MW
              
Coal            
 
Ghent
  1,932   1,932       100.00   1,932 
 
Mill Creek
  1,472   1,472   100.00   1,472     
 
E.W. Brown - Units 1-3
  684   684       100.00   684 
 
Cane Run - Units 4-6
  563   563   100.00   563     
 
Trimble County - Unit 1 (c)
  511   383   75.00   383     
 
Trimble County - Unit 2 (c)
  732   549   14.25   104  60.75   445 
 
Green River
  163   163       100.00   163 
 
OVEC - Clifty Creek (d)
  1,304   106   5.63   73   2.50   33 
 
OVEC - Kyger Creek (d)
  1,086   88   5.63   61   2.50   27 
 
Tyrone (e)
  71   71       100.00   71 
    8,518   6,011     2,656     3,355 
Natural Gas/Oil            
 
E.W. Brown Unit 5 (f)(g)
  132   132   53.00   69   47.00   63 
 
E.W. Brown Units 6-7 (f)
  292   292   38.00   111   62.00   181 
 
E.W. Brown Units 8-11 (g)
  486   486       100.00   486 
 
Trimble County Units 5-6
  314   314   29.00   91   71.00   223 
 
Trimble County Units 7-10
  628   628   37.00   232   63.00   396 
 
Paddy's Run Units 11-12
  35   35   100.00   35     
 
Paddy's Run Unit 13
  147   147   53.00   78   47.00   69 
 
Haefling
  36   36       100.00   36 
 
Zorn
  14   14   100.00   14     
 
Cane Run Unit 11
  14   14   100.00   14     
    2,098   2,098     644     1,454 
Hydro            
 
Ohio Falls
  54   54   100.00   54     
 
Dix Dam
  24   24       100.00   24 
    78   78     54     24 
              
Total
  10,694   8,187     3,354     4,833 

(a)LG&EFERC approved mitigation and KU's properties are primarily located in Kentucky, with the exception of the units owned by OVEC.  Clifty Creek is located in Indiana and Kyger Creek is located in Ohio.
(b)The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units, and may be revised periodically to reflect changed circumstances.
(c)TC1 and TC2 are jointly owned with Illinois Municipal Electric Agency and Indiana Municipal Power Agency.  Each owner is entitled to its proportionate share of the units' total output and funds its proportionate share of capital, fuel and other operating costs.  See Note 146 to the Financial Statements for additional information.
(d)This unit is owned by OVEC.  LKE has a power purchase agreement that entitles LKE to its proportionate share of the unit's total output and LKE funds its proportionate share of fuel and other operating costs.  See Note 15 to the Financial Statements for additional information.
(e)This unit was retired in February 2013.  See Note 8 to the Financial Statements for additional information.
(f)Includes a leasehold interest.  See Note 11 to the Financial Statements for additional information.
(g)There is an inlet air cooling system attributable to these units.  This inlet air cooling system is not jointly owned; however, it is used to increase productioninformation on the units to which it relates, resulting in an additional 10 MW of capacity for LG&E and an additional 88 MW of capacity for KU.announced sales.

For a description of LG&E's and KU's service areas, see "Item 1. Business - Background."  At December 31, 2012, LG&E's transmission system included in the aggregate, 45 substations (32 of which are shared with the distribution system) with a total capacity of 7 million kVA and 917 circuit miles of lines.  LG&E's distribution system included 97 substations (32 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,908 miles of overhead lines and 2,390 miles of underground wires.  KU's transmission system included 134 substations (55 of which are shared with the distribution system) with a total capacity of 13 million kVA and 4,079 circuit miles of lines.  KU's distribution system included 480 substations (55 of which are shared with the transmission system) with transformer capacity of 7 million kVA, 14,134 miles of overhead lines and 2,299 miles of underground conduit.

35
LG&E's natural gas transmission system includes 4,272 miles of gas distribution mains and 388 miles of gas transmission mains, consisting of 255 miles of gas transmission pipeline, 124 miles of gas transmission storage lines, 6 miles of gas combustion turbine lines and 3 miles of gas transmission pipeline in regulator facilities.  Five underground natural gas storage fields, with a total working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to ultimate consumers.  KU's service area includes an additional 11 miles of gas transmission pipeline providing gas supply to natural gas combustion turbine electrical generating units.

Substantially all of LG&E's and KU's respective real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and, in the case of LG&E, the storage and distribution of natural gas, is subject to the lien of either the LG&E 2010 Mortgage Indenture or the KU 2010 Mortgage Indenture.  See Note 7 to the Financial Statements for additional information.

LG&E and KU continuously reexamine development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them or pursue other options.  At December 31, 2012, LG&E and KU planned to implement the following incremental capacity increases and decreases at the following plants located in Kentucky.

            
     LG&E KU  
   Total Net         Date of
   Summer MW         Incremental
   Capacity (a)   Ownership or   Ownership or Capacity
   Increase /   Lease Interest   Lease Interest Increase /
Primary Fuel/Plant (Decrease) % Ownership in MW % Ownership in MW Decrease
              
Coal            
 
Cane Run - Units 4-6 - (b)
 (563) 100.00  (563)     2015 
 
Green River - (b)
 (163)     100.00  (163) 2015 
 
Tyrone - (c)
 (71)     100.00  (71) 2013 
 
Total Capacity Decreases
 (797)   (563)   (234)  
             
Natural Gas            
 
Cane Run - Unit 7 (d)
 640  22.00  141  78.00  499  2015 

(a)The capacity of generating units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances.
(b)LG&E and KU anticipate retiring these units by the endPedricktown includes capacity dedicated to serving landlord load (maximum of 2015.  See Notes 8 and 15 to the Financial Statements for additional information.11 MW).
(c)KU retired this unit in February 2013.  See Note 8 to the Financial Statements for additional information.
(d)In May 2012, LG&E and KU received approval to build this unit at the existing Cane Run site.  See Note 8 to the Financial Statements for additional information.

(PPL)

U.K. Regulated Segment

For a description of WPD's service territory, see "Item 1. Business - Background."  At December 31, 2012, WPD had electric distribution lines in public streets and highways pursuant to legislation and rights-of-way secured from property owners.  WPD's distribution system in the U.K. includes 1,592 substations with a total capacity of 68 million kVA, 57,472 circuit miles of overhead lines and 79,755 cable miles of underground conductors.

(PPL and PPL Electric)

Pennsylvania Regulated Segment

For a description of PPL Electric's service territory, see "Item 1. Business - Background."  At December 31, 2012, PPL Electric had electric transmission and distribution lines in public streets and highways pursuant to franchises and rights-of-way secured from property owners.  PPL Electric's transmission system includes 61 substations with a total capacity of 18 million kVA and 3,973 pole miles in service.  PPL Electric's distribution system includes 339 substations with a total capacity of 12 million kVA, 37,031 circuit miles of overhead lines and 8,098 cable miles of underground conductors in service.  All of PPL Electric's facilities are located in Pennsylvania.  Substantially all of PPL Electric's distribution properties and certain transmission properties are subject to the lien of the PPL Electric 2001 Mortgage Indenture.

See Note 8 to the Financial Statements for information on the Regional Transmission Line Expansion Plan.

36
(PPL and PPL Energy Supply)

Supply Segment

PPL Energy Supply's electric generating capacity (summer rating) at December 31, 2012 was:

           
        PPL Energy Supply's  
         Ownership or  
Primary Fuel/Plant Total MW Capacity (a) % Ownership Lease Interest in MW (a) Location
           
Natural Gas/Oil        
 
Martins Creek
  1,745   100.00   1,745  Pennsylvania
 
Ironwood
  665   100.00   665  Pennsylvania
 
Lower Mt. Bethel
  543   100.00   543  Pennsylvania
 
Combustion turbines
  363   100.00   363  Pennsylvania
     3,316     3,316   
           
Coal        
 
Montour
  1,518   100.00   1,518  Pennsylvania
 
Brunner Island
  1,455   100.00   1,455  Pennsylvania
 
Colstrip Units 1 & 2 (b)
  614   50.00   307  Montana
 
Conemaugh (c)
  1,749   16.25   284  Pennsylvania
 
Colstrip Unit 3 (b)
  740   30.00   222  Montana
 
Keystone (c)
  1,714   12.34   212  Pennsylvania
 
Corette
  153   100.00   153  Montana
     7,943     4,151   
           
Nuclear        
 
Susquehanna (c)
  2,528   90.00   2,275  Pennsylvania
           
Hydro        
 
Various
  604   100.00   604  Montana
 
Various
  175   100.00   175  Pennsylvania
     779     779   
           
Qualifying Facilities        
 
Renewables (d)
  61   100.00   61  Pennsylvania
 
Renewables
  9   100.00   9  Various
     70     70   
           
Total
  14,636     10,591   

(a)The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units, and may be revised periodically to reflect changed circumstances.
(b)Represents the leasehold interest held by PPL Montana.  See Note 11 to the Financial Statements for additional information.
(c)This unit is jointly owned. Each owner is entitled to its proportionate share of the unit's total output and funds its proportionate share of fuel and other operating costs. See Note 1410 to the Financial StatementsStatement for additional information.
(d)Includes facilities owned, controlled or for which PPLTalen Energy Supply has the rights to the output.output through agreements of Talen Energy Marketing with third parties.

Amounts guaranteed by PPL Montour and PPL Brunner Island in connection with an $800 million secured energy marketing and trading facilityCertain of Talen Energy's credit arrangements are secured by liens on the generating facilities owned by PPL Montour and PPL Brunner Island.majority of the plants above. See Note 75 to the Financial Statements for additional information.

PPLTalen Energy's corporate headquarters are located at 835 Hamilton Street, Suite 150, Allentown, PA 18101-1179 under a lease that expires in 2018.

28

Item 3. Legal Proceedings

Talen Energy Corporation and Talen Energy Supply, from timeLLC

The information required with respect to time reexamines development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.  Seethis item can be found in Note 1511 to the Financial Statements, for information on PPL Energy Supply's intention, beginning in April 2015, to place its Corette plant in long-term reserve status.  At December 31, 2012, PPL Energy Supply subsidiaries planned to implement the following incremental capacity increases.

37

       PPL Energy Supply Expected
     Total MW Ownership or Lease In-Service
 Primary Fuel/Plant Location Capacity (a) Interest in MW Date (b)
           
Hydro         
 
Holtwood (c)
 Pennsylvania 125  125 (100%) 2013 
 
Great Falls (d)
 Montana 28  28 (100%) 2013 
           
Total
   153  153    

(a)The capacity of generating units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances.
(b)The expected in-service dates are subject to receipt of required approvals, permits and other contingencies.
(c)This project includes installation of two additional large turbine-generators and the replacement of four existing runners.
(d)This project involves construction of a new powerhouse and retirement of the exiting powerhouse.

ITEM 3. LEGAL PROCEEDINGS

See Notes 5, 6 and 15 to the Financial Statements forwhich provides information regarding legal, tax litigation, regulatory and environmental proceedings and matters.matters and is incorporated by reference into this Item 3.

Item 4. Mine Safety Disclosures

ITEM 4. MINE SAFETY DISCLOSURESTalen Energy Corporation and Talen Energy Supply, LLC

Not applicable.






29
38

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES

See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash" for information regarding certain restrictions on theTalen Energy's ability to pay dividends for PPL, LKE, LG&E and KU.or make distributions.

PPLTalen Energy Corporation

Additional informationTalen Energy Corporation's common stock is traded on the NYSE under the symbol "TLN". The following table sets forth the high and low sales prices for this itemTalen Energy Corporation's common stock for each quarter of the year 2015, as reported on the NYSE.
  For the 2015 Quarters Ended
  Mar. 31 June 30 Sept. 30 Dec. 31
Price per common share: (a)        
High N/A $20.50
 $18.02
 $12.09
Low N/A $16.87
 $9.83
 $5.73

(a)There is no price per common share data available prior to June 1, 2015, which is the date on which Talen Energy Corporation became a publicly traded company.

Talen Energy Corporation has not declared or paid dividends and does not currently expect to declare or pay dividends on its common stock. Instead, Talen Energy Corporation intends to retain earnings to finance the growth and development of its business and for working capital and general corporate purposes. Talen Energy Corporation's ability to pay dividends to holders of its common stock is set forth inlimited by its ability to obtain cash or other assets from its subsidiaries. Further, certain of the sections entitled "Quarterly Financial, Common Stock Priceagreements governing Talen Energy Corporation's subsidiaries' indebtedness, including the Talen Energy Supply RCF and Dividend Data," "Item 12. Security Ownershipthe First Lien Credit and Guaranty Agreement, restrict the ability of Certain Beneficial Ownerscertain of Talen Energy Corporation's subsidiaries to pay dividends or otherwise transfer assets to Talen Energy Corporation. Any payment of dividends will be at the discretion of Talen Energy Corporation's board of directors and Managementwill depend upon various factors then existing, including earnings, financial condition, results of operations, capital requirements, level of indebtedness, contractual restrictions with respect to payment of dividends, restrictions imposed by applicable law, general business conditions and Related Stockholder Matters" and "Shareowner and Investor Information"other factors that Talen Energy Corporation's board of this report.  directors may deem relevant.

At January 31, 2013,29, 2016, there were 66,13053,889 common stock shareownersstockholders of record.

 Issuer Purchase of Equity Securities during the Fourth Quarter of 2012:   
              
    (a)(b)(c)(d)
              
             Maximum Number (or
             Approximate Dollar
          Total Number ofValue) of Shares
          Shares (or Units)(or Units) that May
    Total Number ofAverage PricePurchased as Part ofYet Be Purchased
    Shares (or Units)Paid per SharePublicly AnnouncedUnder the Plans
Period  Purchased (1)(or Unit)Plans of Programsor Programs (1)
October 1 to October 31, 2012      
November 1 to November 30, 2012   4,665 $29.35  
December 1 to December 31, 2012      
Total   4,665 $29.35  
There were no purchases by Talen Energy Corporation of its common stock during the fourth quarter of 2015.

(1)Represents shares of common stock withheld by PPL at the request of its executive officers to pay income taxes upon the vesting of the officers' restricted stock awards, as permitted under the terms of PPL's ICP and ICPKE.

PPLTalen Energy Supply, LLC

There is no established public trading market for PPLTalen Energy Supply's membership interests. PPLTalen Energy Funding, a direct wholly owned subsidiary of PPL,Corporation owns all of PPLTalen Energy Supply's outstanding membership interests. Distributions on the membership interests will be paid as determined by PPLTalen Energy Supply's Board of Managers.

PPLTalen Energy Supply made cash distributions, primarily to its former member, PPL Energy Funding Corporation, of $787$219 million in 20122015 and $316 million$1.9 billion in 2011.2014.



30

ITEM 6. SELECTED FINANCIAL DATA

Talen Energy Corporation's business was formed on June 1, 2015 after the spinoff from PPL and the acquisition by Talen Energy Supply of RJS Power. Talen Energy Supply is considered the accounting predecessor of Talen Energy Corporation. As such, Talen Energy Corporation's consolidated financial information below for 2015 represents twelve months of legacy Talen Energy Supply information consolidated with seven months of RJS information from June 1, 2015, while the 2014 and earlier periods represent only legacy Talen Energy Supply information. See Note 9Notes 1, 3 and 6 to the Financial Statements regardingfor information on the distribution, including $325 millionspinoff and acquisition of cash, of PPL Energy Supply's membership interests in PPL Global to PPL Energy Funding in January 2011.RJS Power.
Talen Energy Corporation (a) (b)
 2015 2014 2013 2012 2011
           
Income Items (in millions)
          
Operating revenues (c) $4,481
 $4,581
 $4,495
 $4,393
 $4,834
Income (Loss) from continuing operations after income taxes attributable to Talen Energy Corporation stockholders (341) 187
 (262) 428
 672
Income (Loss) from discontinued operations (net of income taxes) (d) —
 223
 32
 46
 96
Net Income (Loss) attributable to Talen Energy Corporation stockholders (341) 410
 (230) 474
 768
Balance Sheet Items (in millions) (e)
          
Property, plant and equipment, net $8,587
 $6,436
 $7,174
 $7,293
 $6,486
Total assets 12,826
 10,760
 11,074
 12,375
 13,179
Short-term debt 608
 630
 —
 356
 400
Long-term debt (including current portion) 4,203
 2,218
 2,525
 3,272
 3,024
Common equity 4,303
 3,907
 4,798
 3,848
 4,037
Total capitalization 9,114
 6,755
 7,323
 7,476
 7,461
Income (Loss) per share attributable to Talen Energy Corporation stockholders - Basic (f)          
Income (Loss) from continuing operations $(3.10)
$2.24

$(3.13)
$5.12

$8.04
Income (Loss) from discontinued operations (net of income taxes) (d) $—

$2.67

$0.38

$0.55

$1.15
Net Income (Loss) $(3.10)
$4.91

$(2.75)
$5.67

$9.19
Income (Loss) per share attributable to Talen Energy Corporation stockholders - Diluted (f) 








Income (Loss) from continuing operations $(3.10)
$2.24

$(3.13)
$5.12

$8.04
Income (Loss) from discontinued operations (net of income taxes) (d) $—

$2.67

$0.38

$0.55

$1.15
Net Income (Loss) $(3.10)
$4.91

$(2.75)
$5.67

$9.19

PPL Electric Utilities Corporation

There is no established public trading market for PPL Electric's common stock, as PPL owns 100% of the outstanding common shares.  Dividends paid to PPL on those common shares are determined by PPL Electric's Board of Directors.  PPL Electric paid common stock dividends to PPL of $95 million in 2012 and $92 million in 2011.

LG&E and KU Energy LLC

There is no established public trading market for LKE's membership interests.  PPL owns all of LKE's outstanding membership interests.  Distributions on the membership interests will be paid as determined by LKE's Board of Directors.  LKE made cash distributions to PPL of $155 million in 2012 and $533 million in 2011 (including $248 million from the proceeds of a note issuance).

Louisville Gas and Electric Company

There is no established public trading market for LG&E's common stock, as LKE owns 100% of the outstanding common shares.  Dividends paid to LKE on those common shares are determined by LG&E's Board of Directors.  LG&E paid common stock dividends to LKE of $75 million in 2012 and $83 million in 2011.

39
Kentucky Utilities Company

There is no established public trading market for KU's common stock, as LKE owns 100% of the outstanding common shares.  Dividends paid to LKE on those common shares are determined by KU's Board of Directors.  KU paid common stock dividends to LKE of $100 million in 2012 and $124 million in 2011.

40

ITEM 6.  SELECTED FINANCIAL AND OPERATING DATA
                   
PPL Corporation (a) (b)  2012 (c)  2011 (c)  2010 (c)  2009   2008 
                   
Income Items (in millions)
               
 
Operating revenues
 $ 12,286  $ 12,737  $ 8,521  $ 7,449  $ 7,857 
 
Operating income
   3,109    3,101    1,866    896    1,703 
 Income from continuing operations after income taxes               
  
attributable to PPL shareowners
   1,532    1,493    955    414    857 
 
Net income attributable to PPL shareowners
   1,526    1,495    938    407    930 
Balance Sheet Items (in millions) (d)
               
 
Total assets
   43,634    42,648    32,837    22,165    21,405 
 
Short-term debt
   652    578    694    639    679 
 
Long-term debt
   19,476    17,993    12,663    7,143    7,838 
 
Noncontrolling interests
   18    268    268    319    319 
 
Common equity
   10,480    10,828    8,210    5,496    5,077 
 
Total capitalization
   30,626    29,667    21,835    13,597    13,913 
Financial Ratios               
 
Return on average common equity - %
   13.76    14.93    13.26    7.48    16.88 
 
Ratio of earnings to fixed charges (e)
   2.9    3.1    2.7    1.9    3.1 
Common Stock Data               
 Number of shares outstanding - Basic (in thousands)               
   
Year-end
   581,944    578,405    483,391    377,183    374,581 
   
Weighted-average
   580,276    550,395    431,345    376,082    373,626 
 Income from continuing operations after income taxes               
  
available to PPL common shareowners - Basic EPS
 $ 2.62  $ 2.70  $ 2.21  $ 1.10  $ 2.28 
 Income from continuing operations after income taxes               
  
available to PPL common shareowners - Diluted EPS
 $ 2.61  $ 2.70  $ 2.20  $ 1.10  $ 2.28 
 Net income available to PPL common shareowners -               
  
Basic EPS
 $ 2.61  $ 2.71  $ 2.17  $ 1.08  $ 2.48 
 Net income available to PPL common shareowners -               
  
Diluted EPS
 $ 2.60  $ 2.70  $ 2.17  $ 1.08  $ 2.47 
 
Dividends declared per share of common stock
 $ 1.44  $ 1.40  $ 1.40  $ 1.38  $ 1.34 
 
Book value per share (d)
 $ 18.01  $ 18.72  $ 16.98  $ 14.57  $ 13.55 
 
Market price per share (d)
 $ 28.63  $ 29.42  $ 26.32  $ 32.31  $ 30.69 
 
Dividend payout ratio - % (f)
   55    52    65    128    54 
 
Dividend yield - % (g)
   5.03    4.76    5.32    4.27    4.37 
 
Price earnings ratio (f) (g)
   11.01    10.89    12.13    29.92    12.43 
Sales Data - GWh               
 
Domestic - Electric energy supplied - retail (h)
   42,379    40,147    14,595    38,912    40,374 
 
Domestic - Electric energy supplied - wholesale (h) (i)
   56,302    65,681    75,489    38,988    42,712 
 
Domestic - Electric energy delivered - retail (j)
   66,931    67,806    42,463    36,689    38,013 
 
U.K. - Electric energy delivered (k)
   77,467    58,245    26,820    26,358    27,724 

(a)The earningsEarnings each year were affected by severalcertain items that management considers special.believes are not indicative of ongoing operations. See "Results of Operations - Segment Results"EBITDA and Adjusted EBITDA" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of specialthose items in 2015, 2014, and 2013. Significant pre-tax items in 2012 and 2011 included unrealized gains on derivative contracts of $91 million and 2010.$120 million, while 2012 included a $29 million coal contract modification payment and 2011 included litigation-related credits of $132 million. The earnings were also affected by theacquisitions and sales of various businesses. See Note 96 to the Financial Statements for aadditional information, including discussion of the discontinued operations in 2012, 20112014 and 2010.2013.
(b)See "Item 1A. Risk Factors" and Notes 61 and 1511 to the Financial Statements for a discussion of uncertainties that could affect PPL'sTalen Energy Corporation's future financial condition.
(c)Amounts for prior years have been reclassified to conform to the current presentation related to certain operating revenues and expenses. See "Reclassifications" in Note 1 to the Financial Statements for additional information.
Includes WPD Midlands activity since its April 1, 2011 acquisition date.  Includes LKE activity since its November 1, 2010 acquisition date.
(d)2014 includes an after-tax gain on the sale of the hydroelectric business in Montana of $206 million.
(e)As of each respective year-end.
(e)Computed using earnings and fixed charges of PPL and its subsidiaries.  Fixed charges consist of interest on short- and long-term debt, amortization of debt discount, expense and premium - net, other interest charges, the estimated interest component of operating rentals and preferred securities distributions of subsidiaries.  See Exhibit 12(a) for additional information.
(f)Based onThe calculation of basic and diluted EPS.
(g)Based on year-end market prices.
(h)The electric energy supplied changes in 2010 reflectearnings per share for 2015 utilized the expirationweighted-average shares outstanding during the year assuming the shares issued to PPL's shareholders were outstanding during the entire year and reflects the impact of the PLR contract between PPL EnergyPlusprivate placement of shares to the Riverstone Holders on the spinoff date. For 2014, 2013, 2012 and PPL Electric as of December 31, 2009.
(i)GWh are included until2011, weighted average shares outstanding assumed the transaction closing for facilities thatshares issued to PPL's shareholders at the spinoff date in 2015 were sold.
(j)
(k)
Prior period volumes were restated to include unbilled volumes.
Year 2011 includes eight months of deliveries associated with the acquisition of WPD Midlands as volumes are reported on a one-month lag.
outstanding during those entire years.
41

ITEM 6. SELECTED FINANCIAL AND OPERATING DATA

PPLTalen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Item 6 is omitted as PPLTalen Energy Supply PPL Electric, LKE, LG&E and KU meetmeets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.


31
42

PPL CORPORATION AND SUBSIDIARIES

Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations

This "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" is separately filed by Talen Energy Corporation and Talen Energy Supply. Any information contained herein relating to an individual registrant is filed by such registrant solely on its own behalf, and neither registrant makes any representation as to information relating to the other registrant except that information relating to Talen Energy Supply and its subsidiaries is also attributed to Talen Energy Corporation and information relating to the subsidiaries of Talen Energy Supply is also attributed to Talen Energy Supply. As Talen Energy Corporation is substantially comprised of Talen Energy Supply and its subsidiaries, most disclosures refer to Talen Energy and are intended to be applicable to both registrants.  When identification of a particular registrant or subsidiary is considered important to understanding the matter being disclosed, the specific entity's name is used, in particular, for those few disclosures that apply only to Talen Energy Corporation. Each disclosure referring to a subsidiary applies to both Talen Energy Corporation and Talen Energy Supply and each disclosure referring to Talen Energy Supply applies to Talen Energy Corporation through consolidation.

Talen Energy Corporation's obligation to report under the Securities and Exchange Act of 1934, as amended, commenced on May 1, 2015, the date Talen Energy Corporation's Registration Statement on Form S-1 relating to the spinoff transaction was declared effective by the SEC. Talen Energy Supply is a separate registrant and considered the predecessor of Talen Energy Corporation, and therefore, the financial information prior to June 1, 2015 presented in this Annual Report on Form 10-K for both registrants includes only legacy Talen Energy Supply information. From June 1, 2015, upon completion of the spinoff and acquisition, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information also includes RJS. As such, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information presented in this Annual Report on Form 10-K for 2015 represents twelve months of legacy Talen Energy Supply information consolidated with seven months of RJS information from June 1, 2015, while 2014 and 2013 represent only legacy Talen Energy Supply information.

The information provided in this Item 7following should be read in conjunction with PPL'sthe registrants' Consolidated Financial Statements and the accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions, except per share data, unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

·  "Overview" provides a description of PPL and its business strategy, a summary of Net Income Attributable to PPL Shareowners and a discussion of certain events related to PPL's results of operations and financial condition.
"Overview," which provides Talen Energy's business strategy, key performance measures, an executive summary and a discussion of key competitive power business dynamics.

·  "Results of Operations" provides a summary of PPL's earnings, a review of results by reportable segment and a description of key factors by segment expected to impact future earnings.  This section ends with explanations of significant changes in principal items on PPL's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.
"Results of Operations" includes "Statement of Income Analysis," which addresses significant changes in principal line items on the Statements of Income comparing 2015 with 2014 and 2014 with 2013 on a GAAP basis. The "Margins" discussion, presented by segment, includes a reconciliation of this non-GAAP financial measure to operating income (loss). The "EBITDA and Adjusted EBITDA" discussion, also presented by segment, includes a reconciliation of these non-GAAP financial measures to operating income (loss) and consolidated net income (loss).

·  "Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL's liquidity position and credit profile.  This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.
"Financial Condition - Liquidity and Capital Resources" provides an analysis of Talen Energy's liquidity positions and credit profiles. This section also includes a discussion of forecasted sources and uses of cash as well as rating agencies and credit considerations.

·  "Financial Condition - Risk Management - Energy Marketing & Trading and Other" provides an explanation of PPL's risk management programs"Financial Condition - Risk Management" provides an explanation of the risk management policy relating to Talen Energy's market and credit risk.

·  "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of Talen Energy and that require management to make significant estimates, assumptions and other judgments of inherently uncertain matters.

Overview

Introduction

PPLTalen Energy is an energya North American competitive power generation and utility holdingmarketing company with headquartersheadquartered in Allentown, Pennsylvania. Through subsidiaries, PPL generatesTalen Energy produces and sells electricity, capacity and ancillary services from its fleet of power plants in the northeastern, northwestern and southeastern U.S., markets wholesale and retail energy primarily in the northeastern and northwestern portions of the U.S., delivers electricity to customers in Pennsylvania, Kentucky, Virginia, Tennessee and the U.K. and delivers natural gas to customers in Kentucky.

PPL's principal subsidiaries are shown below (* denotes an SEC registrant):

43


PPL Corporation*
PPL Capital Funding
LKE*
PPL Global
● Engages in the regulated distribution of electricity in the U.K.
PPL Electric*
● Engages in the regulated transmission and distribution of electricity in Pennsylvania
PPL Energy Supply*
LG&E*
● Engages in the regulated generation, transmission, distribution and sale of electricity in Kentucky, and distribution and sale of natural gas in Kentucky
KU*
● Engages in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky
PPL EnergyPlus
● Performs energy marketing and trading activities
● Purchases fuel
PPL Generation
● Engages in the competitive generation of electricity, primarily in Pennsylvania and Montana
Kentucky Regulated
Segment
U.K. Regulated
Segment
Pennsylvania Regulated Segment
Supply
Segment

Business Strategy

PPL's overall strategy is to achieve stable, long-term growth in its regulated electricity delivery businesses through efficient operations and strong customer and regulatory relations, and disciplined optimization of energy supply margins in its energy supply business while mitigating volatility in both cash flows and earnings.  In pursuing this strategy, PPL acquired LKE in November 2010 and WPD Midlands in April 2011.  These acquisitions have reduced PPL's overall business risk profile and reapportioned the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business.  Each of the rate-regulated businesses plans to make material capital investments over the next several years to improve infrastructure and customer reliability.  As a result of these acquisitions,totaling approximately 71% of PPL's assets were in its regulated businesses17,400 MW at December 31, 20122015, principally located in the Northeast, Mid-Atlantic and approximately 73%Southwest regions of "Net Income Attributable to PPL Shareowners" was from regulated businessesthe U.S. See "Item 2. Properties" for the year ended December 31, 2012.additional information on Talen Energy's power plants. For a more detailed description of Talen Energy's business, see "Item 1. Business."


32

Business Strategy

The increase in regulated assets is expected to provide earnings stability through regulated returns on equity and the ability to recover costs of capital investments, in contrast to the competitive energy supply business where earnings and cash flows are subject to commodity market volatility.

Results for periods prior to the acquisitions of LKE and WPD Midlands are not comparable with, or indicative of, results for periods subsequent to the acquisitions.

With the acquisition of WPD Midlands, PPL has a higher proportion of overall earnings subject to foreign currency translation risk.  The U.K. subsidiaries also have currency exposure to the U.S. dollar to the extent they have U.S. dollar denominated debt.  To manage these risks, PPL generally uses contracts such as forwards, options and cross currency swaps that contain characteristics of both interest rate and foreign currency exchange contracts.

PPL's strategy for its energy supply business isTalen Energy seeks to optimize the value from its competitive power generation assets and marketing portfolio.  PPLportfolio while mitigating near-term volatility in both cash flow and earnings metrics. Talen Energy endeavors to doaccomplish this by matching energy supplyprojected output from its generation assets with load, or customer demand, under contracts of varying durations with creditworthy counterparties to capture profitsforward power sales in the wholesale and retail markets while effectively managing exposure to energy and fuel price volatility, counterparty credit risk and operational risk. Talen Energy is focused on safe, reliable, and resilient operations, disciplined capital investment, portfolio optimization, cost management and the pursuit of value enhancing growth opportunities.

To manage financing costs and access to credit markets, and to fund capital expenditures and growth opportunities, a key objective of PPL's business strategyTalen Energy is to maintain a strong credit profile and strongadequate liquidity position.capacity. In addition, PPLTalen Energy has a financial risk management policy and operational risk management programsprocedures that, among other things, are designed to monitor and manage its exposure to earnings and cash flow volatility related to, as applicable, changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of its generating units. To manage these risks, Talen Energy generally uses contracts such as forwards, options, swaps and insurance contracts primarily focused on mitigating cash flow volatility within the next 12 month period.

44
Financial and Operational DevelopmentsKey Performance Measures

Net Income AttributableIn addition to PPL Shareowners

Net Income Attributableoperating income (loss), Talen Energy utilizes Adjusted EBITDA and Margins, both non-GAAP financial measures, as indicators of performance for its business, with Adjusted EBITDA as the primary financial performance measure used by management to PPL Shareownersevaluate its business and monitor results of operations. Results for the years ended December 31 by segment and in total was:were as follows.
 2015 2014 $ Change
Net Income (Loss)$(341) $410
 $(751)
     
Operating Income (Loss)(39) 397
 (436)
     
Adjusted EBITDA1,002
 759
 243
     
Margins1,899
 1,653
 246

   2012  2011  2010  
            
Kentucky Regulated (a) $ 177  $ 221  $ 26  
U.K. Regulated (b)   803    325    261  
Pennsylvania Regulated   132    173    115  
Supply   414    776    612  
Corporate and Other (c)         (76) 
Net Income Attributable to PPL Shareowners $ 1,526  $ 1,495  $ 938  
            
EPS - basic $ 2.61  $ 2.71  $ 2.17  
EPS - diluted $ 2.60  $ 2.70  $ 2.17  

(a)LKE was acquired on November 1, 2010.  Therefore, 2012 and 2011 include a full year of LKE results, while 2010 includes two months of LKE results.
(b)WPD Midlands was acquired on April 1, 2011 and its results are recorded on a one-month lag.  Therefore, 2012 includes a full year of WPD Midlands' results, while 2011 includes eight months of WPD Midlands' results.  2011 was also impacted by certain acquisition related costs.  These costs are considered special items by management and are discussed in further detail in "Results of Operations - Earnings - U.K. Regulated Segment."  See Notes 7 and 10 to the Financial Statements for additional information on the acquisition and related financing.
(c)Includes $22 million, after tax ($31 million, pre-tax), of certain third-party acquisition-related costs, including advisory, accounting, and legal fees associated with the acquisition of LKE that are recorded in "Other Income (Expense) - net" on the Statement of Income.  Also includes $52 million, after tax ($80 million, pre-tax), of 2010 Bridge Facility costs that are recorded in "Interest Expense" on the Statement of Income.  These costs are considered special items by management.  See Notes 7 and 10 to the Financial Statements for additional information on the acquisition and related financing.

Earnings in 2012 increased 2% over 2011 and earnings in 2011 increased 59% over 2010.  The changes in Net Income Attributable to PPL Shareowners from year to year were, in part, attributable to the acquisition of LKE and WPD Midlands and certain items that management considers special.  See "Results of Operations" for a detailed analysis of Talen Energy's results, the definitions of Margins and Adjusted EBITDA and a reconciliation of these non-GAAP measures to related GAAP measures.

Executive Summary

The increase in Margins, a primary driver to changes in the other three earnings measures reflected above, was primarily due to a $237 million increase related to the RJS and MACH Gen generating facilities acquired in 2015.

The declines in operating income (loss) and net income (loss) were substantially due to non-cash goodwill and other asset impairment charges recorded in 2015. Net income (loss) was also negatively impacted by an $80 million after-tax charge related to a debt extinguishment in 2015, and net income (loss) in 2014 benefited from a $206 million after-tax gain on the sale of the hydroelectric generating facilities in Montana. See Note 6 to the Financial Statements for additional information on the sale of the hydroelectric generating facilities.

Several of the key financial and operational developments that impacted results for the year ended December 31, 2015 were as follows:

Spinoff from PPL - During 2015, Talen Energy incurred certain restructuring, TSA and other charges in connection with the spinoff from PPL. See Note 1 to the Financial Statements for additional information on the spinoff, acquisition and related charges.


33

Impairment Charges - During 2015, management considered a number of events and changes in circumstances and concluded that impairment assessments for goodwill and certain long-lived assets were necessary. The charges recorded were as follows:
   Pre-tax After-tax
   Third Quarter Fourth Quarter Total Total
 Goodwill $466
 $(1) $465
 $444
 Sapphire plants and C.P. Crane plant 122
 67
 189
 113
 Total $588
 $66
 $654
 $557

In addition to the impairment assessments that resulted in these charges, management also tested its coal-fired generation facilities located primarily within the PJM market for impairment and concluded that the plants were not impaired at December 31, 2015. The recoverability assessment is very sensitive to forward energy and capacity price assumptions as well as forecasted operation and maintenance and capital spending and further declines could negatively impact future testing results. The carrying value of these coal-fired generation facilities was more than $3 billion as of December 31, 2015. See Notes 14 and 16 to the Financial Statements for additional information on the impairment testing that occurred and the charges recorded in 2015.

Loss on Debt Extinguishment - In conjunction with the termination of a remarketing dealer's right to remarket certain senior unsecured notes, Talen Energy recorded a pre-tax charge of $134 million. See Note 5 to the Financial Statements for additional information.

Coal Contract Modification - To mitigate the risk of oversupply of coal due to reduced dispatching of coal-fired generation facilities, primarily as a result of the continued decline in natural gas prices. Talen Energy incurred pre-tax charges of $41 million in the third quarter of 2015 to reduce its contracted coal deliveries in 2015 through 2018.  

Acquisition of MACH Gen - In November 2015, Talen Energy obtained 2,344 MW (summer rating) of generating capacity with the completion of the acquisition of all of the membership interests of MACH Gen for cash consideration of approximately $600 million. In addition, $578 million of a MACH Gen subsidiary's debt remained outstanding after the acquisition. See Notes 5 and 6 to the Financial Statements for additional information.

Divestiture of Talen Renewable Energy - In November 2015, Talen Energy completed the sale of Talen Renewable Energy for $116 million. See Note 6 to the Financial Statements for additional information.

Divestiture of Ironwood, Holtwood, Lake Wallenpaupack and C.P. Crane Power Plants - In October 2015, Talen Energy announced the sale of these facilities, with an aggregate generating capacity of approximately 1,400 MW, to satisfy a December 2014 FERC order approving the combination of Talen Energy Supply and RJS Power. Upon completion of these divestitures, Talen Energy will have generated $1.5 billion in pre-tax cash proceeds. The sales of Ironwood and C.P. Crane were completed in February 2016. See Note 6 to the Financial Statements for additional information.

Susquehanna Nuclear Plant - The Susquehanna nuclear plant continues to make modifications to address the causes of turbine blade cracking first identified in 2011. Unit 1 completed its planned refueling and turbine inspection outage in June 2014 and installed newly designed shorter last stage blades on one of the low pressure turbines. The same short blade modifications were installed on two of the three turbines on Unit 2 during the spring 2015 scheduled refueling outage. All remaining turbine blade modifications are scheduled to be performed during planned refueling and maintenance outages. The Susquehanna nuclear plant set a single-year generation record and achieved an annualized capacity factor of over 94 percent.

Brunner Island Co-firing Project - Construction is under way and is expected to be completed by the end of 2016. The project is expected to cost $118 million. At December 31, 2015, $23 million of costs associated with the project have been incurred.

Key Competitive Power Business Dynamics

Electricity, natural gas and capacity prices are significant contributors to the profitability of Talen Energy's portfolio. A discussion of PPL's business segments, detailsthe general factors and current market conditions affecting these commodities and Talen Energy's operations follows.

34


Electricity Prices

Electricity prices impact Talen Energy's operations. The price for electricity varies by region and analysiscan be influenced by a host of supply and demand factors including, but not limited to, generator availability, market design, fuel prices for power generators, transmission congestion, demand growth and seasonality. In 2015, delivered prices for electricity fell, relative to 2014 delivered prices, across the competitive power markets in which Talen Energy operates, primarily driven by unusual market and weather volatility in the first quarter of 2014 and a continued decline in natural gas prices, which are discussed below.

The table below reflects the average around-the-clock day ahead electricity prices at various pricing points located near Talen Energy's power plants for the years ended December 31.
 2015 (a) 2014 (a) 2013 (a)
PJM - West Hub$35.82
 $51.01
 $38.42
      
PJM - PPL Zone33.01
 52.13
 38.01
      
PJM - BGE Hub43.73
 60.22
 41.53
      
ERCOT - North25.31
 35.74
 33.19
      
ERCOT - South25.85
 36.02
 33.76
      
NYISO - Zone F38.00
 61.19
 50.47
      
ISO-NE Mass Hub41.90
 64.56
 56.42

(a)Source: data obtained from applicable ISO/RTO publications.

If a decline in electricity prices driven by declining gas prices persists, Talen Energy will likely experience lower energy Margins at its coal-fired and nuclear generation facilities as higher priced hedges expire. To mitigate the impact of the consolidated resultsdeclining Margins on coal-fired and nuclear generation facilities, as described above, Talen Energy is pursuing opportunities to modify certain of operations.

Economic and Market Conditions

Unregulated Gross Energy Margins associated with PPL Energy Supply's competitiveits coal-fired generation and marketing business are impacted by changes in market prices and demand for electricityfacilities to be capable of operating on both coal and natural gas, as well as evaluating cost reduction measures at these facilities.

In November 2015, the FERC issued an order on "Price Formation" in the energy and ancillary service markets. These changes and future changes signaled by the FERC in that order may eventually improve pricing and thus compensation for generators in the energy and ancillary services markets, but no assurances can be given that will occur.

In December 2015, the FERC accepted a previously submitted PJM proposal that permits cost-based offers to exceed $2,000/MWh in certain circumstances but limits cost-based offers to $2,000/MWh for the purpose of setting locational marginal prices. Under the proposal, market-based offers are permitted to rise along with cost-based offers but are not permitted to exceed $2,000/MWh or the corresponding cost-based offers. Moreover, electricity providers will be permitted to recover actual costs above $2,000MWh through make-whole payments. In addition, electricity prices will be permitted to rise to $3,700/MWh during certain shortage pricing events. The changes became effective in December 2015.

However, in January 2016, as a part of the Price Formation efforts, the FERC issued a Notice of Proposed Rulemaking (NOPR) for comment which requires each RTO, including PJM, to cap each resource's incremental electricity offer to the higher of $1,000/MWh or that resource's verified cost-based incremental electricity offer. Under this proposal, verified cost-based incremental electricity offers above $1,000/MWh would be used for purposes of calculating Locational Marginal Prices. Comments on this NOPR are due within 60 days and final FERC action on this proposed ruling could modify the above December 2015 acceptance of the PJM proposal.

Capacity Prices

Capacity prices are another key source of revenue for Talen Energy’s operations. Currently, about 80% of Talen Energy's generation capacity is located in markets with a capacity product, including assets in PJM, NYISO and ISO-NE. Similar to electricity, capacity prices are affected by supply and demand fundamentals such as power plant availability, competitionadditions and retirements, imports/exports of capacity from/to adjacent markets, costs associated with plant retrofits, risk premiums associated with penalties for non-performance, demand response products, ISO demand forecasts and reserve margin targets. Over the past three auction cycles, capacity prices have increased in PJM and ISO-NE, primarily attributable to incentive-based changes in the markets for retail customers, fuel costs andcapacity market structures designed to improve operational availability fuel transportation costs and other costs.  Current depressed wholesale marketduring periods of peak demand.

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The table below reflects the cleared capacity prices for electricitythe zones in which the majority of Talen Energy's plants are located for the three most recent strip auctions.
 2015/2016 (a) 2016/2017 (a) 2017/2018 (a)
PJM - MAAC ($/MW-day)$167.46
 $119.13
 $120.00
      
PJM - SWMAAC ($/MW-day)167.46
 119.13
 120.00
      
PJM - RTO ($/MW-day)136.00
 59.37
 120.00
      
PJM Capacity Performance ($/MW-day) (b)N/A
 134.00
 151.50
      
NYISO - Rest of State ($/kW-month) (c)1.25
 N/A
 N/A
      
ISO-NE - Rest of Pool ($/kW-month)3.43
 3.15
 15.00

(a)Source: data obtained from applicable ISO/RTO publications.
(b)The capacity performance product percentage of reliability requirements is being phased in through the 2020/2021 auction as described below.
(c)
Represents the 2015/2016 winter strip auction. Auctions beyond 2015/2016 have not yet been conducted.

As a result of unusual market and weather volatility in the first quarter of 2014, PJM determined that changes were necessary to ensure system reliability. In December 2014, PJM proposed to add an enhanced Capacity Performance (CP) product to the capacity market structure to permit additional compensation for generation owners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirements, with higher penalties for non-performers. In June 2105, the FERC issued an order approving the PJM CP proposal largely as it was filed and the CP product is being phased in through the 2020/2021 auction based on a percentage of capacity to meet reliability requirements. The phase in percentage was set at 60% for 2016/2017, 70% for 2017/2018 and 80% for both 2018/2019 and 2019/2020. 2020/2021 will be the first auction to procure 100% of the CP product. In August 2015, PJM completed the first base residual auction inclusive of a CP product for the planning year 2018/2019 and subsequently, in late August and September 2015, PJM completed the two CP transitional auctions for planning years 2016/2017 and 2017/2018. The first CP product implementation will begin on June 1, 2016 for the portion procured in the 2016/2017 transitional auction.

In December 2015, PJM altered its process for forecasting load beginning with the most recent 2016 "Load Processing Report" to reflect a shorter period for historical weather data, updated end usage data, and the inclusion of distributed solar generation. The revised process lowered the load forecast. This reduction in load is expected to put downward pressure on PJM capacity prices.

In January 2016, the U.S. Supreme Court reversed the ruling of the U.S. Court of Appeals for the D.C. Circuit Court and upheld the FERC's jurisdiction over rules regarding DR in organized markets. Therefore, DR will be permitted to continue to participate in future PJM energy and capacity auctions.

Natural Gas Prices

Natural gas prices are a key aspect of the current competitive power environment. The extensive development of major shale formations in the U.S. over the past few years has caused natural gas prices to decline. Power prices have resulted fromalso declined substantially due to the high degree of correlation with natural gas prices, weak general weak economic conditions and other factors, including the impact of expanded domestic shale gas development and production.factors. As a result, of these factors, PPLTalen Energy Supply has experienced a shift in the dispatching of its competitive generation fleet from coal-fired to combined-cycle gas-fired generation as illustrated in the following table:generation.  

   Average Utilization Factors (a)
   2012   2009 - 2011
Pennsylvania coal plants  69%  87%
Montana coal plants  67%  89%
Combined-cycle gas plants  98%  72%
Environmental Regulations

(a)All periods reflect the year ended December 31.

This reduction in coal-fired generation output had resulted in a surplus of coal inventory at certain of PPLTalen Energy Supply's Pennsylvania coal plants.  To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million in 2012 to reduce its 2012 and 2013 contracted coal deliveries.  PPL Energy Supply will continue to manage its coal inventory to mitigate the financial impact and physical implications of an oversupply; however, no additional coal contract modifications are expected at this time.

In addition, current economic and commodity market conditions indicate a lower value of unhedged future energy margins (primarily in 2014 and forward years) compared to the energy margins in 2012.  As has been PPL Energy Supply's practice in periods of changing business conditions, PPL Energy Supply continues to review its future business and operational plans, including capital and operation and maintenance expenditures, as well as its hedging strategies, to help counter the financial effects of low commodity prices.

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PPL's businesses areis subject to extensive federal, state and local environmental laws, rules and regulations.  Although PPLregulations, including those pertaining to CCRs, GHG, effluent limitation guidelines and MATS.  In 2015, the EPA published the final rules related to GHG regulations for new and existing power plants that could have a significant industry-wide impact. Talen Energy Supply's competitive generation assets are well positioned to meetis in the process of evaluating these requirements, certain regulated generation assets at LG&E and KU will require substantial capital investment.  LG&E and KU project $2.3 billion of capital investment over the next five years to satisfy certain of these requirements.rules. See Note 15 to the Financial Statements"Financial Condition - Environmental Matters" below for additional information on these requirements.  These requirements have resulted in LKE's anticipated retirementIn 2015, Talen Energy recorded increases to existing AROs of five coal-fired units with a combined summer capacity rating of 726 MW by 2015.  KU retired the 71 MW unit at the Tyrone plant in February 2013.  See Note 8 to the Financial Statements for additional information regarding the anticipated retirement of these units as well as plans to build a combined-cycle natural gas facility in Kentucky.  Also, in 2012 KU recorded a $25$41 million pre-tax impairment of its EEI investment as a result of environmental regulationsa review of the 2015 CCR rule. Further changes to AROs may be required as estimates are refined and low energy prices.  Finally, in September 2012 PPL announced its intention, beginning in April 2015, to place its Corette plant in long-term reserve status, suspendingcompliance with the plant's operation due to expected market conditions and the costs to comply with MATS.  The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million.  Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.rule continues.


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Other Regulatory Matters

In lightThere have been attempts in Ohio by certain companies to have their utilities be permitted to subsidize several uneconomic merchant generation assets owned by non-utility affiliates. Those attempts are being opposed by many generator and consumer interests both in Ohio and at the FERC. Additional efforts to oppose on grounds of these economic and market conditions, as well as current and projected environmental regulatory requirements, PPL considered whether certain of its other generating assets were impaired, and determined that no impairment charges were required at December 31, 2012.  PPL is unable to predict whether future environmental requirements or market conditions will result in impairment charges for other generating assets or other retirements.

PPL and its subsidiariesfederal preemption may also be impactedmade in future periods byFederal Court. If approved and not reversed, out of market subsidies could be disruptive to the uncertaintymarket signals for competitive generation and threaten the long-term viability of PJM's markets. It is too early to predict the outcome of these efforts to subsidize uneconomic generators in the worldwide financial and credit markets.  In addition, PPL may be impacted by reductions in the credit ratings of financial institutions and evolving regulations in the financial sector.  Collectively, these factors could reduce availability or restrict PPL and its subsidiaries' ability to maintain sufficient levels of liquidity, reduce capital market activities, change collateral posting requirements and increase the associated costs to PPL and its subsidiaries.Ohio.

PPLTalen Energy cannot predict the future impact that thesefuture economic and market conditions and regulatory requirements may have on its financial condition or results of operations.

Susquehanna Turbine Blade Inspection

During 2012, PPL Energy Supply performed inspections of the Unit 1 and Unit 2 turbine blades at the PPL Susquehanna nuclear power plant in order to further address the issue of turbine blade cracking that was first identified in 2011.  The after-tax earnings impact of these 2012 inspections, including reduced energy-sales margins and repair expenses, was approximately $53 million.  The after-tax earnings impact of turbine blade related outages in 2011 was approximately $63 million.

Ironwood Acquisition

In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility.  The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021.  The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM.  See Note 10 to the Financial Statements for additional information.

Bankruptcy of SMGT

In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Montana.  At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure.  This contract was accounted for as NPNS by PPL EnergyPlus.
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The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices.  Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract.  In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February.  In March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT bankruptcy trustee and PPL EnergyPlus to terminate the SMGT Contract.  As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell to other customers the electricity previously contracted to SMGT under the SMGT Contract.

PPL EnergyPlus' receivable under the SMGT Contract totaled approximately $21 million at December 31, 2012, which has been fully reserved.

In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding.  The total claim is approximately $375 million, including the above receivable, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract.  No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.

PPL Energy Supply cannot predict any amounts that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.

Tax Litigation

In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD.  PPL filed its federal tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable.  In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes.  As a result, and with finalization of other issues, PPL recorded a $42 million tax benefit in 2010.  In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit).  In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision, holding that the U.K. WPT is not a creditable tax.  As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011.  In February 2012, PPL filed its petition for rehearing of the Third Circuit's opinion.  In March 2012, the Third Circuit denied PPL's petition.  In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company.  In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion.  The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013.  PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.

Terminated Bluegrass CTs Acquisition

In September 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals.  In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs.  In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs.  In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns.  After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable.  In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.

Cane Run Unit 7 Construction

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7.  In May 2012, the KPSC issued an order approving the request.  A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings.  LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015.  The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
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Future Capacity Needs

In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs.  As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.

Storm Costs

During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  However, a PPL subsidiary has a $10 million reinsurance policy with a third party insurer, for which a receivable was recorded with an offsetting credit to "Other operation and maintenance" on the Statement of Income.  PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income).  In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.

See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for information on $84 million of storm costs incurred in 2011.

Rate Case Proceedings

Pennsylvania

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013.  In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million.  The approved rates became effective January 1, 2013.

Also, in its December 28, 2012 final order, the PUC ordered PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order.  PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.

Kentucky

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E.  In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement.  Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E.  The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU.  The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%.  On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement.  The new rates became effective on January 1, 2013.  In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

Regional Transmission Line Expansion Plan

Susquehanna-Roseland

In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid.  PJM determined that the line was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system.  PJM directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.
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On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review.  On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation; and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint.  PPL Electric has intervened in the lawsuit.  The chosen route had previously been approved by the PUC and New Jersey Board of Public Utilities.

On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.

Construction activities have begun on portions of the 101-mile route in Pennsylvania.  The line is expected to be completed before the peak summer demand period of 2015.  At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.

PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.

Northeast/Pocono

In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities).  The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project.  The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive.  The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit to the FERC in March 2013.  PPL Electric expects the project to be completed in 2017.  At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.

Legislation - Regulatory Procedures and Mechanisms

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC.  Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets.  In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for the implementation of Act 11.  Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC.  The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC.  In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC.  The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.

FERC Formula Rates

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization.  This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC.  At December 31, 2012 and December 31, 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets."  In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34 year period beginning June 1, 2012.

U.K. Tax Rate Change

In July 2012, the U.K.'s Finance Act of 2012 (the Act) became effective.  The Act reduced the U.K. statutory income tax rate from 25% to 24%, retroactive to April 1, 2012 and from 24% to 23%, effective April 1, 2013.  As a result of these changes, PPL recognized a deferred tax benefit of $75 million in 2012.
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Ofgem Review of Line Loss Calculation

WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4.  Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4.  In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability.  In March 2012, Ofgem issued a decision regarding the preferred methodology.  In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013.  In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013.  In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses.  Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology.  This consultation also confirmed the final decisions will be published by April 2013.  In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date.  PPL cannot predict when this matter will be resolved.

Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period.  That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.

Equity Forward Contract

In April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock.  In conjunction with that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.

In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL's common stock.  Settlement of these initial forward sale agreements will occur no later than April 2013.  As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the additional 591 thousand shares of PPL common stock.  Settlement of the subsequent forward sale agreements will occur no later than July 2013.

PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements.  PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.

The forward sale agreements are classified as equity transactions.  As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements.  Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method.  See Note 7 to the Financial Statements for additional information.

2010 Equity Units

During 2013, two events will occur related to the components of the 2010 Equity Units.  PPL will receive proceeds of $1.150 billion through the issuance of PPL common stock to settle the 2010 Purchase Contracts and PPL Capital Funding expects to remarket the 4.625% Junior Subordinated Notes due 2018.  See Note 7 to the Financial Statements for additional information.

Redemption of PPL Electric Preference Stock

In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share.  The price paid for the redemption was the par value, without premium ($250 million in the aggregate).  At December 31, 2011, the preference stock was reflected in "Noncontrolling Interests" on PPL's Balance Sheet.
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Results of Operations

The "StatementAs a result of Income Analysis" explains the year-to-year changes in significant earnings components, including certain income statement line items, Kentucky Gross Margins, Pennsylvania Gross Delivery Margins and Unregulated Gross Energy Margins.

On AprilRJS Power acquisition on June 1, 2011, PPL completed its acquisition2015, results for RJS (since the date of WPD Midlands.  As PPL is consolidating WPD Midlands on a one-month lag, consistent with its accounting policy on consolidation of foreign subsidiaries, a full year of WPD Midlands' results of operationsacquisition) are included in PPL'sTalen Energy's 2015 results for 2012, and eight months of WPD Midlands' results of operations are included in PPL's results for 2011, with no comparable amounts for 2010.in 2014 and 2013. When discussing PPL'sTalen Energy's results of operations for 20122015 compared with 2011 and 2011 compared with 2010,2014, the results of WPD MidlandsRJS are isolated for purposes of comparability.  WPD Midlands'comparability (if significant). At acquisition, the Sapphire operations were classified as discontinued operations. However, in November 2015, when the FERC approved the third mitigation package excluding the Sapphire portfolio, the assets and liabilities and operating results were reclassified to held and used and to continuing operations, as it is no longer probable that the Sapphire portfolio will be sold.

As a result of the MACH Gen acquisition on November 2, 2015, results for MACH Gen (since the date of acquisition) are included within "Segment Results - U.K. Regulated Segment (formerlyin Talen Energy's 2015 results with no comparable amounts in 2014 and 2013. When discussing Talen Energy's results of operations for 2015 compared with 2014, the International Regulated Segment, renamedresults of MACH Gen are isolated for purposes of comparability (if significant).

Talen Energy is organized in 2012)."two segments: East and West, based on geographic location. The East segment includes the generating, marketing and trading activities in PJM, NYISO and ISO-NE. The West segment includes the generating, marketing and trading activities located in ERCOT and WECC. See Note 102 to the Financial Statements for additional information regardingon Talen Energy's segments and the acquisition.segment reevaluation.

On November 1, 2010, PPL completed its acquisition of LKE.  LKE's results of operations are included in PPL's results for the full year of 2012 and 2011, while 2010 includes LKE's operating results for the two months ended December 31, 2010.  When discussing PPL's results of operations for 2011 compared with 2010, the results of LKE are isolated for purposes of comparability.  LKE's results are shown separatelyThe discussion within "Segment Results - Kentucky Regulated Segment."  See Note 10 to the Financial Statements for additional information regarding the acquisition.

Tables analyzing changes in amounts between periods within "Segment Results" and "Statement of Income Analysis" are presentedaddresses significant changes in principal line items on the Statements of Income comparing 2015 with 2014 and 2014 with 2013 on a constant U.K. foreign currency exchange rate basis, where applicable, in orderGAAP basis. The "Margins" discussion, presented by segment, includes a reconciliation of that non-GAAP financial measure to isolate the impactoperating income(loss). The "EBITDA and Adjusted EBITDA" discussion, also presented by segment, includes a reconciliation of the change in the exchange rate on the item being explained.  Results computed on a constant U.K. foreign currency exchange rate basis are calculated by translating current year results at the prior year weighted-average U.K. foreign currency exchange rate.

Earnings         
           
   2012  2011  2010 
           
Net Income Attributable to PPL Shareowners $ 1,526  $ 1,495  $ 938 
EPS - basic $ 2.61  $ 2.71  $ 2.17 
EPS - diluted $ 2.60  $ 2.70  $ 2.17 

Kentucky Regulated Segment

The Kentucky Regulated segment consists primarily of LKE's results from the operation of regulated electricity generation, transmissionthose non-GAAP financial measures to operating income (loss) and distribution assets, primarily in Kentucky, as well as in Virginia and Tennessee.  This segment also includes LKE's results from the regulated distribution and sale of natural gas in Kentucky.

Net Income Attributable to PPL Shareowners includes the following results:

   2012  2011  % Change 2010 (a)
            
Utility revenues $ 2,759  $ 2,793   (1) $ 493 
Fuel   872    866   1    139 
Energy purchases   195    238   (18)   68 
Other operation and maintenance   778    751   4    139 
Depreciation   346    334   4    49 
Taxes, other than income   46    37   24    2 
 Total operating expenses   2,237    2,226      397 
Other Income (Expense) - net   (15)   (1)  1,400    (1)
Other-Than-Temporary Impairments   25     n/a   
Interest Expense (b)   219    217   1    55 
Income Taxes   80    127   (37)   16 
Income (Loss) from Discontinued Operations (net of income taxes)   (6)   (1)  500    2 
Net Income Attributable to PPL Shareowners $ 177  $ 221   (20) $ 26 

(a)Represents the results of operations for the two-month period from November 1, 2010 through December 31, 2010.
(b)Includes allocated interest expense of $68 million in 2012, $70 million in 2011 and $31 million in 2010 related to the 2010 Equity Units and interest rate swaps.
51
The changes in the components of the Kentucky Regulated segment's results between 2012 and 2011 were due to the following factors, which reflect reclassifications for items included in Kentucky Gross Margins and certain items that management considers special.  See additional detail of these special items in the table below.  The 2011 and 2010 comparison has not been included as the periods are not comparable (2010 includes two months of activity as LKE was acquired on November 1, 2010)consolidated net income (loss).

2012 vs. 2011
Kentucky Gross Margins$ (8)
Other operation and maintenance (16)
Depreciation (10)
Taxes, other than income (9)
Other Income (Expense) - net (14)
Interest Expense (2)
Income Taxes 31 
Special items, after-tax (16)
Total$ (44)

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Kentucky Gross Margins.

·
Higher other operation and maintenance in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.

·Higher depreciation in 2012 compared with 2011 due to PP&E additions.

·Lower other income (expense) - net in 2012 compared with 2011 primarily due to losses from the EEI investment.

·Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income.

The following after-tax gains (losses), which management considers special items, also impacted the Kentucky Regulated segment's results.

   Income Statement           
   Line Item 2012  2011   2010 
             
Adjusted energy-related economic activity, net, net of tax of $0, ($1), $1Utility Revenues     $ 1   $ (1)
Impairments:            
 Other asset impairments, net of tax of $10, $0, $0 (a)Other-Than-Temporary-Impairments $ (15)        
LKE acquisition-related adjustments:            
 Net operating loss carryforward and other tax-related adjustmentsIncome Taxes and Other O&M   4         
Other:            
 LKE discontinued operations, net of tax of $4, $1, ($2) (b)Disc. Operations   (5)    (1)    2 
Total  $ (16)  $   $1 

(a)KU recorded an impairment of its equity method investment in EEI.  See Note 18 to the Financial Statements for additional information.
(b)2012 includes an adjustment to an indemnification liability.

2013 Outlook

Excluding special items, PPL projects higher segment earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.

Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7"Item 7. Combined Management's Discussion and Notes 6Analysis of Financial Condition and 15Results of Operations" and Note 11 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.


U.K. Regulated Segment
37

Statement of Income Analysis, Margins, EBITDA and Adjusted EBITDA

The U.K. Regulated segment consists primarilyStatement of the regulated electric distribution operations in the U.K.  As a result of the WPD Midlands acquisition on April 1, 2011, the U.K. Regulated segment includes eight months of WPD Midlands' results in 2011.  Similar to PPL WW, WPD Midlands' results are recorded on a one-month lag.Income Analysis --
52
Net Income Attributable to PPL Shareowners includes the following results (includes PPL WW and WPD Midlands on a consolidated basis, except for 2012 and 2011 acquisition-related adjustments, which are shown separately):
 For the Years Ended December 31,   For the Years Ended December 31,  
 2015 2014 Change 2014 2013 Change
Wholesale energy (a) (b) (c)$2,828
 $2,653
 $175
 $2,653
 $2,890
 $(237)
Wholesale energy to affiliate (b)14
 84
 (70) 84
 51
 33
Retail energy (a) (b)1,095
 1,243
 (148) 1,243
 1,027
 216
Energy-related businesses544
 601
 (57) 601
 527
 74
Total Operating Revenues4,481
 4,581
 (100) 4,581
 4,495
 86
Fuel (a) (b) (c)1,194
 1,196
 (2) 1,196
 1,048
 148
Energy purchases (a) (b) (c)676
 1,054
 (378) 1,054
 1,153
 (99)
Operation and maintenance1,052
 1,007
 45
 1,007
 961
 46
Loss on lease termination—
 —
 —
 —
 697
 (697)
Impairments657
 —
 657
 —
 65
 (65)
Depreciation356
 297
 59
 297
 299
 (2)
Taxes, other than income65
 57
 8
 57
 53
 4
Energy-related businesses520
 573
 (53) 573
 512
 61
Total Operating Expenses4,520
 4,184
 336
 4,184
 4,788
 (604)
Operating Income (Loss)(39) 397
 (436) 397
 (293) 690
Other Income (Expense) - net(118) 30
 (148) 30
 32
 (2)
Interest Expense211
 124
 87
 124
 159
 (35)
Income Taxes(27) 116
 (143) 116
 (159) 275
Income (Loss) from Continuing Operations After Income Taxes(341) 187
 (528) 187
 (261) 448
Income (Loss) from Discontinued Operations (net of income taxes)—
 223
 (223) 223
 32
 191
Net Income (Loss)(341) 410
 (751) 410
 (229) 639
Net Income (Loss) Attributable to Noncontrolling Interests—
 —
 —
 —
 1
 (1)
Net Income (Loss) Attributable to Talen Energy Corporation Stockholders$(341) $410
 $(751) $410
 $(230) $640

   2012  2011  2010 
           
Utility revenues (a) $ 2,289  $ 1,618  $ 727 
Energy-related businesses   47    35    34 
 Total operating revenues   2,336    1,653    761 
Other operation and maintenance   439    374    182 
Depreciation   279    211    117 
Taxes, other than income   147    113    52 
Energy-related businesses   34    17    17 
 Total operating expenses   899    715    368 
Other Income (Expense) - net   (51)   13    3 
Interest Expense (b)   421    336    135 
Income Taxes   153    98    
WPD Midlands acquisition-related adjustments, net of tax   (9)   (192)   
Net Income Attributable to PPL (c) $ 803  $ 325  $ 261 

(a)Includes $1,423 million in 2012 and $790 million in 2011 for WPD Midlands.
(b)Includes allocated interest expense of $47 million and $38 million for 2012 and 2011 related primarily to the 2011 Equity Units.
(c)Includes $570 million in 2012 and $137 million in 2011 for WPD Midlands, net of acquisition-related adjustments.

The changes in the components of the U.K. Regulated segment's results between these periods were due to the following factors, which reflect reclassifications for certain items that management considers special and with WPD Midlands isolated for comparability purposes.  See additional detail of special items in the table below.  The amounts for PPL WW and WPD Midlands are presented on a constant U.K. foreign currency exchange rate basis in order to isolate the impact of the change in the exchange rate.

   2012 vs. 2011 2011 vs. 2010
PPL WW      
 Utility revenues $ 49  $ 77 
 Other operation and maintenance   (26)   (10)
 Interest expense   16    (14)
 Depreciation   (8)   (2)
 Other   (4)   5 
 Income taxes   17    (55)
WPD Midlands, after-tax   224    240 
U.S.      
 Interest expense and other   (15)   (41)
 Income taxes   (25)   37 
Foreign currency exchange rates, after-tax   (14)   15 
Special items, after-tax   264    (188)
Total $ 478  $ 64 
PPL WW
·The increase in utility revenues in 2012 compared with 2011 was due to the impact of the April 2012 and 2011 price increases which resulted in $78 million of higher utility revenues, partially offset by $13 million of lower volumes due primarily to a downturn in the economy and weather.

The increase in utility revenues in 2011 compared with 2010 was due to the impact of the April 2011 and 2010 price increases that resulted in $76 million of additional revenue.

·The increases in other operation and maintenance in 2012 compared with 2011 and 2011 compared with 2010 were due to higher pension expense resulting from an increase in amortization of actuarial losses.

·The decrease in interest expense in 2012 compared with 2011 was due to lower interest expense on index-linked notes.

The increase in interest expense in 2011 compared with 2010 was due to $11 million of higher interest expense arising from a March 2010 debt issuance.

·The increase in depreciation expense in 2012 compared with 2011 was due to $10 million of depreciation related to PP&E additions.
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·  The decrease in income taxes in 2012 compared with 2011 was due to the tax deductibility of interest on acquisition financing of $12 million and $9 million from a benefit relating to customer contributions for capital expenditures.

The increase in income taxes in 2011 compared with 2010 was due to a $46 million benefit recorded in 2010 for realized capital losses that offset a gain relating to a business activity sold in 1999 and $15 million due to higher 2011 pre-tax income.
WPD Midlands
·  Earnings in 2012 compared with 2011 were affected by an additional four months of results in 2012 totaling $171 million, after-tax.

·  The comparable eight month period was affected by higher utility revenue of $125 million resulting from the April 1, 2012 price increase and $26 million of lower pension expense, partially offset by $26 million of higher taxes due to higher pre-tax income, $25 million of additional interest expense on debt issuances in 2011 and 2012 and $25 million of higher taxes due to a U.K./U.S. intercompany tax transaction.
U.S.
·The increase in interest expense and other in 2012 compared with 2011 was due to $9 million of higher interest expense primarily associated with the 2011 Equity Units issued to finance the WPD Midlands acquisition.

The increase in interest expense and other in 2011 compared with 2010 was due to $38 million of higher interest expense primarily associated with the 2011 Equity Units issued to finance the WPD Midlands acquisition.

·The increase in income taxes in 2012 compared with 2011 was due to $28 million of tax benefits recorded in 2011 as a result of U.K. pension plan contributions and a $20 million adjustment primarily related to the recalculation of 2010 U.K. earnings and profits, partially offset by $25 million from the U.K./U.S. intercompany tax transaction.

The decrease in income taxes in 2011 compared with 2010 was due to a $41 million tax benefit resulting from changes in the taxable amount of planned U.K. cash repatriations, a tax benefit of $28 million from U.K. pension plan contributions and lower income taxes due to lower 2011 pre-tax income.  These tax benefits were partially offset by $24 million of favorable 2010 adjustments to uncertain tax benefits primarily related to Windfall Profits Tax and $11 million of higher income taxes on interest income related to acquisition financing.

Foreign Currency Exchange Rates
·Changes in foreign currency exchange rates negatively affected the segment's earnings for 2012 compared with 2011 and positively affected 2011 compared with 2010.  The weighted-average exchange rates for the British pound sterling, including the effects of currency hedges, were approximately $1.58 in 2012, $1.61 in 2011, and $1.57 in 2010.

The following after-tax gains (losses), which management considers special items, also impacted the U.K. Regulated segment's results.

   Income Statement         
   Line Item 2012  2011  2010 
Foreign currency-related economic hedges, net of tax of $18, ($2), $0 (a)Other Income-net $(33) $5  $1 
WPD Midlands acquisition-related adjustments:          
 2011 Bridge Facility costs, net of tax of $0, $14, $0 (b)Interest Expense     (30)   
 Foreign currency loss on 2011 Bridge Facility, net of tax of $0, $19, $0 (c)Other Income-net     (38)   
 Net hedge gains, net of tax of $0, ($17), $0 (c)Other Income-net     38    
 Hedge ineffectiveness, net of tax of $0, $3, $0 (d)Interest Expense     (9)   
 U.K. stamp duty tax, net of tax of $0, $0, $0 (e)Other Income-net     (21)   
 Separation benefits, net of tax of $4, $26, $0 (f)Other O&M  (11)  (75)   
 Other acquisition-related adjustments, net of tax of ($1), $20, $0(g)  2   (57)   
Other:          
 Change in U.K. tax rate (h)Income Taxes  75    69    18 
 Windfall profits tax litigation (i)Income Taxes      (39)   12 
 Line loss adjustment, net of tax of ($23), $0, $0 (j)Utility Revenues  74       
Total  $ 107  $ (157) $ 31 
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(a)Represents unrealized gains (losses) on contracts that economically hedge anticipated earnings denominated in GBP.
(b)Represents fees incurred in connection with establishing the 2011 Bridge Facility.
(c)Represents the foreign currency loss on the repayment of the 2011 Bridge Facility, including a pre-tax foreign currency loss of $15 million associated with proceeds received on the U.S. dollar-denominated senior notes issued by PPL WEM in April 2011 that were used to repay a portion of PPL WEM's borrowing under the 2011 Bridge Facility.  The foreign currency risk was economically hedged with forward contracts to purchase GBP, which resulted in pre-tax gains of $55 million.
(d)Represents a combination of ineffectiveness associated with closed out interest rate swaps and a charge recorded as a result of certain interest rate swaps failing hedge effectiveness testing.
(e)Tax on the transfer of ownership of property in the U.K., which is not tax deductible for income tax purposes.
(f)2012 represents severance compensation and early retirement deficiency costs.  2011 primarily represents severance compensation, early retirement deficiency costs and outplacement services for employees separating from the WPD Midlands companies as a result of a reorganization to transition the WPD Midlands companies to the same operating structure as WPD (South West) and WPD (South Wales).  2011 also includes severance compensation and early retirement deficiency costs associated with certain employees who separated from the WPD Midlands companies, but were not part of the reorganization.
(g)2011 primarily includes $34 million, pre-tax, of advisory, accounting and legal fees which are recorded in "Other Income (Expense) - net" on the Statement of Income; $37 million, pre-tax, of costs, primarily related to the termination of certain contracts, rebranding costs and relocation costs that were recorded to "Other operation and maintenance" expense on the Statement of Income; and $6 million, pre-tax, of costs associated with the integration of certain information technology assets, that were recorded in "Depreciation" on the Statement of Income.
(h)The U.K. Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013.  The U.K. Finance Act of 2011, enacted in July 2011, reduced the U.K. statutory income tax rate from 27% to 26% retroactive to April 1, 2011 and reduced the rate from 26% to 25% effective April 1, 2012.  The U.K. Finance Act of 2010, enacted in July 2010, reduced the U.K. statutory income tax rate from 28% to 27% effective April 1, 2011.  As a result, WPD reduced its net deferred tax liabilities and recognized deferred tax benefits in 2012, 2011 and 2010.  WPD Midlands' portion of the deferred tax benefit was $43 million and $35 million for 2012 and 2011.
(i)In 2010, the U.S. Tax Court ruled in PPL's favor in a pending dispute with the IRS concluding that the 1997 U.K. Windfall Profits Tax (WPT) imposed on all U.K. privatized utilities, including PPL's U.K. subsidiary, is a creditable tax for U.S. Federal income tax purposes.  As a result, PPL recorded an income tax benefit in 2010.  In January 2011, the IRS appealed the U.S. Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit).  In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision and holding that the WPT is not a creditable tax.  As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011.  See Note 5 to the Financial Statements for information on 2012 activities related to this case, including the U.S. Supreme Court's decision to grant PPL's petition for a writ of certiorari to review the Third Circuit's opinion.
(j)In November 2012, Ofgem issued additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses.  Based on applying the preferred methodology for DPCR4, WPD Midlands reduced its line loss liability by $86 million, pre-tax.  Ofgem also indicated that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period.  As a result, WPD Midlands reduced their line loss accrual by $11 million, pre-tax.  This represents WPD Midlands' portion of the adjustment as the original liability was primarily established through purchase accounting.

2013 Outlook

Excluding special items, PPL projects higher segment earnings in 2013 compared with 2012, primarily driven by higher electricity delivery revenue and lower income taxes, partially offset by higher operation and maintenance, higher depreciation and higher interest expense.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.

Pennsylvania Regulated Segment

The Pennsylvania Regulated segment includes the regulated electric delivery operations of PPL Electric.

Net Income Attributable to PPL Shareowners includes the following results:
55
   2012  2011  % Change 2011  2010  % Change
Operating revenues                
 External $ 1,760  $ 1,881  (6) $ 1,881  $ 2,448  (23)
 Intersegment   3    11  (73)   11    7  57 
 Total operating revenues   1,763    1,892  (7)   1,892    2,455  (23)
Energy purchases                
 External   550    738  (25)   738    1,075  (31)
 Intersegment   78    26  200    26    320  (92)
Other operation and maintenance   576    530  9    530    502  6 
Amortization of recoverable transition costs       n/a       n/a
Depreciation   160    146  10    146    136  7 
Taxes, other than income   105    104  1    104    138  (25)
 Total operating expenses   1,469    1,544  (5)   1,544    2,171  (29)
Other Income (Expense) - net   9    7  29    7    7  - 
Interest Expense   99    98  1    98    99  (1)
Income Taxes   68    68  -    68    57  19 
Net Income   136    189  (28)   189    135  40 
Net Income Attributable to Noncontrolling Interests (Note 3)   4    16  (75)   16    20  (20)
Net Income Attributable to PPL Shareowners $ 132  $ 173  (24) $ 173  $ 115  50 

The changes in the components of the Pennsylvania Regulated segment's results between these periods were due to the following factors, which reflect reclassifications for items included in Pennsylvania Gross Delivery Margins.

  2012 vs. 2011 2011 vs. 2010
       
Pennsylvania Gross Delivery Margins $ 19  $ 66 
Other operation and maintenance   (50)   4 
Depreciation   (14)   (10)
Taxes, other than income   (9)   4 
Other   1    1 
Income Taxes      (11)
Noncontrolling Interests   12    4 
Total $ (41) $ 58 

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins.

·  Higher other operation and maintenance for 2012 compared with 2011, primarily due to $17 million in higher payroll-related costs due to less project costs being capitalized in 2012, higher support group costs of $11 million and $10 million for increased vegetation management.

·  Higher depreciation for 2012 compared with 2011 and 2011 compared with 2010 primarily due to PP&E additions.

·  Higher taxes, other than income for 2012 primarily due to a $10 million tax provision related to gross receipts tax.

·Income taxes were flat in 2012 compared with 2011 primarily due to the $22 million impact of lower 2012 pre-tax income primarily offset by $9 million of depreciation not normalized and $9 million of income tax return adjustments, largely related to changes in flow-through regulated tax depreciation.

Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher 2011 pre-tax income, partially offset by a $14 million tax benefit related to changes in flow-through regulated tax depreciation.

·  Lower noncontrolling interests in 2012 compared with 2011 due to PPL Electric's redemption of preference securities in June 2012.

2013 Outlook

PPL projects higher segment earnings in 2013 compared with 2012, due to higher distribution revenues from a distribution base rate increase effective January 1, 2013, and higher transmission margins, partially offset by higher depreciation.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
56
Supply Segment

The Supply segment primarily consists of the energy marketing and trading activities, as well as the competitive generation and development operations of PPL Energy Supply.  In 2011 and 2010, PPL Energy Supply subsidiaries completed the sale of several businesses, which have been classified as Discontinued Operations.  See Note 9 to the Financial Statements for additional information.

Net Income Attributable to PPL Shareowners includes the following results:

   2012  2011  % Change 2011  2010  % Change
Energy revenues                
 External (a) $ 4,970  $ 5,938   (16) $ 5,938  $ 4,444   34 
 Intersegment   79    26   204    26    320   (92)
Energy-related businesses   461    472   (2)   472    375   26 
 Total operating revenues   5,510    6,436   (14)   6,436    5,139   25 
Fuel (a)   965    1,080      1,080    1,096   
Energy Purchases                
 External (a)   1,810    2,277   (21)   2,277    1,344   69 
 Intersegment   2    4   (50)   4    3   33 
Other operation and maintenance   1,032    882   17    882    934   (6)
Depreciation   315    262   20    262    254   3 
Taxes, other than income   68    72   (6)   72    46   57 
Energy-related businesses   450    467   (4)   467    366   28 
 Total operating expenses   4,642    5,044   (8)   5,044    4,043   25 
Other Income (Expense) - net   18    43   (58)   43    (9)  (578)
Other-Than-Temporary Impairments   2    6   (67)   6    3   100 
Interest Expense   222    192   16    192    224   (14)
Income Taxes   247    463   (47)   463    228   103 
Income (Loss) from Discontinued Operations      3   (100)   3    (19)  (116)
Net Income   415    777   (47)   777    613   27 
Net Income Attributable to Noncontrolling Interests   1    1      1    1   
Net Income Attributable to PPL Shareowners $ 414  $ 776   (47) $ 776  $ 612   27 

(a)Includes the impact from energy-related economic activity. See "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements for additional information.

The changes in the components of the Supply segment's results between these periods were due to the following factors, which reflect reclassifications for items included in Unregulated Gross Energy Margins and certain items that management considers special.  See additional detail of these special items in the table below.

  2012 vs. 2011 2011 vs. 2010
       
Unregulated Gross Energy Margins $ (197) $ (405)
Other operation and maintenance   (91)   (63)
Depreciation   (53)   (8)
Taxes, other than income   8    (10)
Other Income (Expense) - net   (26)   22 
Interest Expense   (20)   (12)
Other   5    (4)
Income Taxes   136    107 
Discontinued operations, after-tax - excluding certain revenues and expenses included in margins      17 
Special items, after-tax   (124)   520 
Total $ (362) $ 164 

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Unregulated Gross Energy Margins.

·Higher other operation and maintenance in 2012 compared with 2011 due to higher costs at PPL Susquehanna of $27 million including refueling outage costs, payroll-related costs and project costs, $18 million due to the Ironwood Acquisition, $13 million due to eastern fossil and hydroelectric unit outages, $11 million of higher pension expense and $10 million of higher charges from support groups.

Higher other operation and maintenance in 2011 compared with 2010 primarily due to higher costs at PPL Susquehanna of $27 million largely due to unplanned outages, the refueling outage and payroll-related costs, $23 million higher costs at eastern fossil and hydroelectric units largely due to outages, and $12 million higher net costs at western fossil and hydroelectric units, largely resulting from insurance recoveries received in 2010.
57
·Higher depreciation in 2012 compared with 2011 primarily due to a $24 million impact from PP&E additions and $17 million due to the Ironwood Acquisition.

·Lower taxes other than income in 2012 compared with 2011 primarily due to lower capital stock tax.

Higher taxes other than income in 2011 compared with 2010 primarily due to higher capital stock tax.

·Lower other income (expense) - net in 2012 compared with 2011 and higher other income (expense) - net in 2011 compared with 2010 primarily due to a $22 million gain on the July 2011 redemption of Senior Secured Bonds.

·Higher interest expense in 2012 compared with 2011 primarily due to hedging activity, which increased interest expense by $30 million and $12 million related to the debt assumed as a result of the Ironwood Acquisition, partially offset by $11 million of lower interest on short-term borrowings and $4 million of higher capitalized interest.

Higher interest expense in 2011 compared with 2010 of $13 million primarily due to hedging activity and $8 million due to short-term borrowings, partially offset by $15 million of higher capitalized interest.

·Lower income taxes in 2012 compared with 2011 due to lower 2012 pre-tax income, which reduced income taxes by $151 million and $23 million related to lower adjustments to valuation allowances on Pennsylvania net operating losses, partially offset by $21 million related to the impact of prior period tax return adjustments.

Lower income taxes in 2011 compared with 2010 due to lower 2011 pre-tax income, which reduced taxes by $204 million and a $26 million reduction in deferred tax liabilities related to an updated blended state tax rate resulting from a change in state tax apportionment.  These decreases were partially offset by $101 million related to adjustments to valuation allowances on Pennsylvania net operating losses, $16 million in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction resulting from revised bonus depreciation estimates.

The following after-tax gains (losses), which management considers special items, also impacted the Supply segment's results.

   Income Statement         
   Line Item 2012  2011  2010 
           
Adjusted energy-related economic activity, net, net of tax of ($26), ($52), $85(a) $ 38  $ 72  $ (121)
Sales of assets:          
 Maine hydroelectric generation business, net of tax of $0, $0, ($9) (b)Disc. Operations         15 
 Sundance indemnification, net of tax of $0, $0, $0Other Income-net         1 
Impairments:          
 Emission allowances, net of tax of $0, $1, $6 (c)Other O&M      (1)   (10)
 Renewable energy credits, net of tax of $0, $2, $0Other O&M      (3)   
 Adjustments - nuclear decommissioning trust investments, net of tax of ($2), $0, $0Other Income-net   2       
 Other asset impairments, net of tax of $0, $0, $0Other O&M   (1)      
LKE acquisition-related adjustments:          
 Monetization of certain full-requirement sales contracts, net of tax of $0, $0, $89(d)         (125)
 Sale of certain non-core generation facilities, net of tax of $0, $0, $37 (e)Disc. Operations      (2)   (64)
 Discontinued cash flow hedges and ineffectiveness, net of tax of $0, $0, $15 (f)Other Income-net         (28)
 Reduction of credit facility, net of tax of $0, $0, $4 (g)Interest Expense         (6)
Other:          
 Montana hydroelectric litigation, net of tax of $0, ($30), $22(h)      45    (34)
 Litigation settlement - spent nuclear fuel storage, net of tax of $0, ($24), $0 (i)Fuel      33    
 Health care reform - tax impact (j)Income Taxes         (8)
 Montana basin seepage litigation, net of tax of $0, $0, ($1)Other O&M         2 
 Counterparty bankruptcy, net of tax of $5, $5, $0 (k)Other O&M   (6)   (6)   
 Wholesale supply cost reimbursement, net of tax of $0, ($3), $0(l)   1    4    
 Ash basin leak remediation adjustment, net of tax of ($1), $0, $0Other O&M   1       
 Coal contract modification payments, net of tax of $12, $0, $0 (m)Fuel   (17)      
Total  $ 18  $ 142  $ (378)
(a)See "Reconciliation of Economic Activity" below.
(b)Gains recorded on the completion of the sale of the Maine hydroelectric generation business.  See Note 9 to the Financial Statements for additional information.
(c)Primarily represents impairment charges of sulfur dioxide emission allowances.
(d)In July 2010, in order to raise additional cash for the LKE acquisition, certain full-requirement sales contracts were monetized that resulted in cash proceeds of $249 million.  See "Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information.  $343 million of pre-tax gains were recorded to "Wholesale energy marketing" and $557 million of pre-tax losses were recorded to "Energy purchases" on the Statement of Income.
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(e)Consists primarily of the initial impairment charge recorded when the business was classified as held for sale.  See Note 9 to the Financial Statements for additional information.
(f)As a result of the expected net proceeds from the anticipated sale of certain non-core generation facilities, coupled with the monetization of certain full-requirement sales contracts, debt that had been planned to be issued by PPL Energy Supply in 2010 was no longer needed.  As a result, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued.
(g)In October 2010, PPL Energy Supply made borrowings under its Syndicated Credit Facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE.  Subsequent to the repayment of such borrowing, the capacity was reduced, and as a result, PPL Energy Supply wrote off deferred fees in 2010.
(h)In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds.  In 2010, PPL Montana recorded a pre-tax charge of $56 million, representing estimated rental compensation for years prior to 2010, including interest.  Of this total charge $47 million, pre-tax, was recorded to "Other operation and maintenance" and $9 million, pre-tax, was recorded to "Interest Expense" on the Statement of Income.  In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter.  In June 2011, the U.S. Supreme Court granted PPL Montana's petition.  In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion.  Prior to the U.S. Supreme Court decision, $4 million, pre-tax, of interest expense on the rental compensation covered by the court decision was accrued in 2011.  As a result of the U.S. Supreme Court decision, PPL Montana reversed its total pre-tax loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $79 million pre-tax is considered a special item because it represented $65 million of rent for periods prior to 2011 and $14 million of interest accrued on the portion covered by the prior court decision.  These amounts were credited to "Other operation and maintenance" and "Interest Expense" on the Statement of Income.  See Note 15 to the Financial Statements for additional information.
(i)In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant.  PPL Susquehanna recorded credits to fuel expense to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant.  This special item represents amounts recorded
(b)Amounts included in 2011 to cover the costs incurred from 1998 through December 2010."Margins" and are not discussed separately.
(j)Represents income tax expense recorded as a result of the provisions within Health Care Reform which eliminated the tax deductibility of retiree health care costs
(c)Amounts for prior years have been reclassified to conform to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.
(k)In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code.  In 2012, PPL EnergyPlus recorded an additional allowance for unpaid amounts under the long-term power contract.  In March 2012, the U.S. Bankruptcy Court for the District of Montana approved the request to terminate the contract, effective Aprilcurrent presentation. See "Reclassifications" in Note 1 2012.
(l)In January 2012, PPL received $7 million pre-tax, related to electricity delivered to a wholesale customer in 2008 and 2009, recorded in "Wholesale energy marketing-Realized."  The additional revenue results from several transmission projects approved at PJM for recovery that were not initially anticipated at the time of the electricity auctions and therefore were not included in the auction pricing.  A FERC order was issued in 2011 approving the disbursement of these supply costs by the wholesale customer to the suppliers, therefore, PPL accrued its share of this additional revenue in 2011.
(m)As a result of lower electricity and natural gas prices, coal-fired generation output decreased during 2012.  Contract modification payments were incurred to reduce 2012 and 2013 contracted coal deliveries.
Reconciliation of Economic Activity

The following table reconciles unrealized pre-tax gains (losses) from the table within "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements to the special item identified as "Adjusted energy-related economic activity, net."

    2012  2011  2010 
Operating Revenues         
  Unregulated retail electric and gas $ (17) $ 31  $ 1 
  Wholesale energy marketing   (311)   1,407    (805)
Operating Expenses         
  Fuel   (14)   6    29 
  Energy Purchases   442    (1,123)   286 
Energy-related economic activity (a)   100    321    (489)
Option premiums (b)   (1)   19    32 
Adjusted energy-related economic activity   99    340    (457)
Less:  Unrealized economic activity associated with the monetization of certain         
 full-requirement sales contracts in 2010 (c)         (251)
Less:  Economic activity realized, associated with the monetization of certain         
 full-requirement sales contracts in 2010   35    216    
Adjusted energy-related economic activity, net, pre-tax $ 64  $ 124  $ (206)
            
Adjusted energy-related economic activity, net, after-tax $ 38  $ 72  $ (121)

(a)See Note 19 to the Financial Statements for additional information.
(b)Adjustment for the net deferral and amortization of option premiums over the delivery period of the item that was hedged or upon realization.  Option premiums are recorded in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statements of Income.
(c)See "Components of Monetization of Certain Full-Requirement Sales Contracts" below.

Components of Monetization of Certain Full-Requirement Sales Contracts

The following table provides the components of the "Monetization of Certain Full-Requirement Sales Contracts" special item.
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2010 
Full-requirement sales contracts monetized (a)$ (68)
Economic activity related to the full-requirement sales contracts monetized (146)
Monetization of certain full-requirement sales contracts, pre-tax (b)$ (214)
Monetization of certain full-requirement sales contracts, after-tax$ (125)

(a)See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information.
(b)Includes unrealized losses of $251 million, which are reflected in "Wholesale energy marketing - Unrealized economic activity" and "Energy purchases - Unrealized economic activity" on the Statement of Income.  Also includes net realized gains of $37 million, which are reflected in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statement of Income.

2013 Outlook

Excluding special items, PPL projects lower segment earnings in 2013 compared with 2012, primarily driven by lower energy prices, higher fuel costs, higher operation and maintenance, higher depreciation and higher financing costs, which are partially offset by higher capacity prices and higher nuclear generation output despite scheduled outages for both Susquehanna units to implement a long-term solution to turbine blade issues.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Note 15 to the Financial Statementsbelow for a discussion of the risks, uncertainties and factors that may impact future earnings.

Statementcomponents of the changes to Net Income Analysis --

Margins

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as three non-GAAP financial measures:  "Kentucky Gross Margins," "Pennsylvania Gross Delivery Margins" and "Unregulated Gross Energy Margins."  These measures are not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance.  Other companies may use different measures to analyze and to report on the results of their operations.  PPL believes that these measures provide additional criteria to make investment decisions.  These performance measures are used, in conjunction with other information, internally by senior management and the Board of Directors to manage the Kentucky Regulated, Pennsylvania Regulated and Supply segment operations, analyze each respective segment's actual results compared with budget and, in certain cases, to measure certain corporate financial goals used in determining variable compensation.

PPL's three non-GAAP financial measures include:

·"Kentucky Gross Margins" is a single financial performance measure of the Kentucky Regulated segment's electricity generation, transmission and distribution operations as well as its distribution and sale of natural gas.  In calculating this measure, fuel and energy purchases are deducted from revenues.  In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset.  These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives.  Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation."  As a result, this measure represents the net revenues from the Kentucky Regulated segment's operations.

·"Pennsylvania Gross Delivery Margins" is a single financial performance measure of the Pennsylvania Regulated segment's electric delivery operations, which includes transmission and distribution activities.  In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings.  Costs associated with these mechanisms are recorded in "Energy purchases," "Other operation and maintenance," which is primarily Act 129 costs, and "Taxes, other than income," which is primarily gross receipts tax.  This performance measure includes PLR energy purchases by PPL Electric from PPL EnergyPlus, which are reflected in "PLR intersegment utility revenue (expense)" in the table below.  As a result, this measure represents the net revenues from the Pennsylvania Regulated segment's electric delivery operations.
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·"Unregulated Gross Energy Margins" is a single financial performance measure of the Supply segment's competitive energy non-trading and trading activities.  In calculating this measure, the Supply segment's energy revenues, which include operating revenues associated with certain Supply segment businesses that are classified as discontinued operations, are offset by the cost of fuel, energy purchases, certain other operation and maintenance expenses, primarily ancillary charges, gross receipts tax, which is recorded in "Taxes, other than income," and operating expenses associated with certain Supply segment businesses that are classified as discontinued operations.  This performance measure is relevant to PPL due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Unregulated Gross Energy Margins."  This volatility stems from a number of factors, including the required netting of certain transactions with ISOs and significant fluctuations in unrealized gains and losses.  Such factors could result in gains or losses being recorded in either "Wholesale energy marketing" or "Energy purchases" on the Statements of Income.  This performance measure includes PLR revenues from energy sales to PPL Electric by PPL EnergyPlus, which are recorded in "PLR intersegment utility revenue (expense)" in the table below.  PPL excludes from "Unregulated Gross Energy Margins" the Supply segment's adjusted energy-related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of PPL's competitive generation assets, full-requirement sales contracts and retail activities.  This economic value is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged.  Also included in adjusted energy-related economic activity is the ineffective portion of qualifying cash flow hedges, the monetization of certain full-requirement sales contracts and premium amortization associated with options.  This economic activity is deferred, with the exception of the full-requirement sales contracts that were monetized, and included in Unregulated Gross Energy Margins over the delivery period that was hedged or upon realization.
Reconciliation of Non-GAAP Financial Measures

The following tables reconcile "Operating Income" to PPL's three non-GAAP financial measures.

     2012  2011 
          Unregulated            Unregulated       
     Kentucky PA Gross Gross       Kentucky PA Gross Gross      
     Gross Delivery Energy    Operating Gross Delivery Energy     Operating
     Margins Margins Margins Other (a) Income (b) Margins Margins Margins Other (a) Income (b)
                          
Operating Revenues                               
 Utility$ 2,759  $ 1,760     $ 2,289 (d) $ 6,808  $ 2,791  $ 1,881     $ 1,620 (d) $ 6,292 
 PLR intersegment utility                               
  revenue (expense) (e)     (78) $ 78              (26) $ 26        
 Unregulated retail                               
  electric and gas        865    (21)(g)   844          696    30 (g)   726 
 Wholesale energy marketing                               
   Realized        4,412    21 (f)   4,433          3,745    62 (f)   3,807 
   Unrealized economic                               
    activity           (311)(g)   (311)            1,407 (g)   1,407 
 Net energy trading margins        4        4          (2)       (2)
 Energy-related businesses           508     508             507     507 
   Total Operating Revenues  2,759    1,682    5,359    2,486     12,286    2,791    1,855    4,465    3,626     12,737 
                                    
Operating Expenses                               
 Fuel  872       931    34 (h)   1,837    866       1,151    (71)(h)   1,946 
 Energy purchases                               
   Realized  195    550    2,204    48 (f)   2,997    238    738    912    242 (f)   2,130 
   Unrealized economic                               
    activity           (442)(g)   (442)            1,123 (g)   1,123 
 Other operation and                               
  maintenance  101    104    19    2,611     2,835    90    108    16    2,453     2,667 
 Depreciation  51          1,049     1,100    49          911     960 
 Taxes, other than income     91    34    241     366       99    30    197     326 
 Energy-related businesses           484     484             484     484 
 Intercompany eliminations     (3)   3              (11)   3    8     
   Total Operating Expenses  1,219    742    3,191    4,025     9,177    1,243    934    2,112    5,347     9,636 
 Discontinued operations                        12    (12)(i)   
Total$ 1,540  $ 940  $ 2,168  $ (1,539)  $ 3,109  $ 1,548  $ 921  $ 2,365  $ (1,733)  $ 3,101 
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     2010   
          Unregulated                    
     Kentucky PA Gross Gross                  
     Gross Delivery Energy    Operating            
     Margins (c) Margins Margins Other (a) Income (b)          
                          
Operating Revenues                               
 Utility   $ 2,448     $ 1,220 (d) $ 3,668                 
 PLR intersegment utility                               
  revenue (expense) (e)     (320) $ 320                        
 Unregulated retail                               
  electric and gas        414    1     415                 
 Wholesale energy marketing                               
   Realized        4,511    321 (f)   4,832                 
   Unrealized economic                               
    activity           (805)(g)   (805)                
 Net energy trading margins        2        2                 
 Energy-related businesses           409     409                 
   Total Operating Revenues     2,128    5,247    1,146     8,521                 
                                    
Operating Expenses                               
 Fuel        1,132    103 (h)   1,235                 
 Energy purchases                               
   Realized     1,075    1,389    309 (f)   2,773                 
   Unrealized economic                               
    activity           (286)(g)   (286)                
 Other operation and                               
  maintenance     76    23    1,657     1,756                 
 Amortization of recoverable                               
  transition costs                               
 Depreciation           556     556                 
 Taxes, other than income     129    14    95     238                 
 Energy-related businesses           383     383                 
 Intercompany eliminations     (7)   3    4                     
   Total Operating Expenses     1,273    2,561    2,821     6,655                 
 Discontinued operations        84    (84)(i)                   
Total   $ 855  $ 2,770  $ (1,759)  $ 1,866                 

(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.
(c)LKE was acquired on November 1, 2010.  Kentucky Gross Margins were not used to measure the financial performance of the Kentucky Regulated segment in 2010.
(d)Primarily represents WPD's utility revenue.  2010 also includes LKE's utility revenues(Loss) for the two-month period subsequent to the November 1, 2010 acquisition.
(e)Primarily related to PLR supply sold by PPL EnergyPlus to PPL Electric.
(f)Represents energy-related economic activity as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.  For 2012, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax loss of $35 million related to the monetization of certain full-requirement sales contracts.  2011 includes a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $19 million related to the amortization of option premiums.  2010 includes a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $32 million related to the amortization of option premiums.
(g)Represents energy-related economic activity, which is subject to fluctuations in value due to market price volatility, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.
(h)Includes economic activity related to fuel as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.  2012 includes a net pre-tax loss of $29 million related to coal contract modification payments.  2011 includes pre-tax credits of $57 million for the spent nuclear fuel litigation settlement.
(i)Represents the net of certain revenues and expenses associated with certain businesses that are classified as discontinued operations.  These revenues and expenses are not reflected in "Operating Income" on the Statements of Income.

Changes in Non-GAAP Financial Measures

The following table shows PPL's three non-GAAP financial measures, as well as the change between periods. The factors that gave rise to the changes are described below the table.
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   2012  2011  Change 2011  2010  Change
                    
Kentucky Gross Margins (a) $ 1,540  $ 1,548  $ (8) $ 1,548     $ 1,548 
                    
PA Gross Delivery Margins by Component                  
 Distribution $ 730  $ 741  $ (11) $ 741  $ 679  $ 62 
 Transmission   210    180    30    180    176    4 
Total $ 940  $ 921  $ 19  $ 921  $ 855  $ 66 
                    
Unregulated Gross Energy Margins by Region                  
Non-trading                  
 Eastern U.S. $ 1,865  $ 2,018  $ (153) $ 2,018  $ 2,429  $ (411)
 Western U.S.   299    349    (50)   349    339    10 
Net energy trading   4    (2)   6    (2)   2    (4)
Total $ 2,168  $ 2,365  $ (197) $ 2,365  $ 2,770  $ (405)

(a)LKE was acquired on November 1, 2010.  Kentucky Gross Margins were not used to measure the financial performance of the Kentucky Regulated segment in 2010.

Kentucky Gross Margins

Margins decreased in 2012 compared with 2011, primarily due to $6 million of lower wholesale margins, resulting from lower market prices.  Retail margins were $2 million lower, as volumes were impacted by unseasonably mild weather during the first four months of 2012.  Total heating degree days decreased 11% compared to 2011, partially offset by a 6% increase in cooling degree days.

PPL acquired LKE on November 1, 2010.  Margins for 2011 are included in PPL's results without comparable amounts for 2010.

Pennsylvania Gross Delivery Margins

Distribution

Margins decreased in 2012 compared with 2011, primarily due to a $14 million unfavorable effect of mild weather early in 2012Net Income (Loss) and lower revenue applicable to certain energy-related costs of $3 million due to fewer PLR customers in 2012, partially offset by a $7 million charge recorded in 2011 to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC.

Margins increased in 2011 compared with 2010, largely due to the PPL Electric distribution rate case which increased rates by approximately 1.6% effective January 1, 2011, resulting in improved residential distribution margins of $68 million.  Additionally, residential volume variances increased margins by an additional $4 million in 2011, compared with 2010, offset by unfavorable weather of $3 million for residential customers in 2011 compared with 2010.  Lastly, lower demand charges and increased efficiency as a result of Act 129 programs resulted in a $5 million decrease in margins for commercial and industrial customers.

Transmission

Margins increased in 2012 compared with 2011, primarily due to increased investment in plant and the recovery of additional costs through the FERC formula-based rates.

Unregulated Gross Energy Margins
Eastern U.S.
The changes in Eastern U.S. non-trading margins were:
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  2012 vs. 2011 2011 vs. 2010
       
Baseload energy prices $ (121) $ (109)
Baseload capacity prices   (37)   (90)
Intermediate and peaking capacity prices   (17)   (58)
Full-requirement sales contracts (a)   (15)   70 
Impact of non-core generation facilities sold in the first quarter of 2011   (12)   (48)
Higher nuclear fuel prices   (12)   (10)
Net economic availability of coal and hydroelectric units (b)   (10)   (72)
Higher coal prices   (2)   (40)
Nuclear generation volume (c)      (29)
Intermediate and peaking Spark Spreads   11    24 
Retail electric   15    (7)
Ironwood Acquisition, which eliminated tolling expense (d)   41    
Monetization of certain deals that rebalanced the business and portfolio      (41)
Other   6    (1)
  $ (153) $ (411)

(a)Higher margins in 2011 compared with 2010 were driven by the monetization of loss contracts in 2010 and lower customer migration to alternative suppliers in 2011.
(b)Volumes were lower in 2011 compared with 2010 as a result of unplanned outages and the sale of our interest in Safe Harbor Water Power Corporation.
(c)Volumes were flat in 2012 compared to 2011 due to an uprate in the third quarter of 2011 offset by higher plant outage costs in 2012.  Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011.
(d)See Note 10 to the Financial Statements for additional information.

Western U.S.

Non-trading margins were lower in 2012 compared with 2011 due to $34 million of lower wholesale volumes, including $31 million related to the bankruptcy of SMGT, $9 million of higher average fuel prices and $9 million of lower wholesale prices.

Non-trading margins were higher in 2011 compared with 2010 due to higher net wholesale prices of $58 million, partially offset by lower wholesale volumes of $45 million, primarily due to economic reductions in the coal unit output.

Utility Revenues      
          
The increase (decrease) in utility revenues was due to:
     2012 vs. 2011 2011 vs. 2010
Domestic:      
 PPL Electric (a) $(121) $ (567)
 LKE (b)  (34)   2,300 
 Total Domestic  (155)  1,733 
          
U.K.:      
 PPL WW      
  Price (c)   78    76 
  Volume (d)  (13)   (15)
  Recovery of allowed revenues (e)  (6)   7 
  Foreign currency exchange rates  (11)   25 
  Other  (10)   8 
  Total PPL WW  38    101 
 WPD Midlands (f)  633    790 
 Total U.K.  671    891 
Total $516  $ 2,624 

(a)See "Pennsylvania Gross Delivery Margins" for further information.
(b)See "Kentucky Gross Margins" for further information.
(c)The increase in 2012 compared with 2011 was due to price increases effective April 1, 2012 and April 1, 2011.  The increase in 2011 compared with 2010 was due to price increases effective April 1, 2011 and April 1, 2010.
(d)The decreases in both periods were primarily due to the downturn in the economy and the unfavorable effect of weather.
(e)The decrease in 2012 compared with 2011 was primarily due to a 2012 charge to income for the over-recovery of revenues from customers.  The increase in 2011 compared with 2010 was primarily due to a revised estimate of network electricity line losses.
(f)Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results.  The increase in 2012 compared with 2011 was primarily due to four additional months of utility revenue in 2012 of $446 million.  The comparable eight month period was $125 million higher in 2012 compared to 2011 due to a price increase effective April 1, 2012.
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Other Operation and Maintenance
         
       
The increase (decrease) in other operation and maintenance was due to:
         
    2012 vs. 2011 2011 vs. 2010
Domestic:      
 LKE (a)    $ 612 
 LKE coal plant maintenance (b) $ 19    
 Act 129 costs incurred (c)   (6)  26 
 Vegetation management (d)   11    (8)
 Montana hydroelectric litigation (e)   75    (121)
 PPL Susquehanna nuclear plant costs (f)   27   27 
 Costs at Western fossil and hydroelectric plants (g)   (1)  12 
 Costs at Eastern fossil and hydroelectric plants (h)   13   23 
 Ironwood acquisition (i)   18    
 Payroll-related costs (j)   26    11 
 PUC-reportable storm costs, net of insurance recoveries   14    (10)
 Uncollectible accounts (k)   (4)   21 
 Pension expense   19    (5)
 Stock based compensation   17    7 
 Other   2    (12)
U.K. Regulated Segment:      
 PPL WW (l)   23    15 
 WPD Midlands (m)   (85)   313 
   $ 168  $ 911 

(a)2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results.
(b)2012 compared with 2011 was higher primarily due to $11 million of expense related to an increased scope of scheduled outages.
(c)Relates to costs associated with PPL Electric's PUC-approved energy efficiency and conservation plan.  These costs are recovered in customer rates.  There were initially 15 Act 129 programs which began in 2010 and continued to ramp up in 2011.  Some of the energy efficiency programs were reduced or closed in 2012 resulting in lower operation and maintenance expense.
(d)PPL Electric incurred more expense in 2010 and 2012 compared to 2011 due to increased vegetation management activities related to transmission lines to comply with federal reliability requirements as well as increased vegetation management for the distribution system in 2012 in an effort to maintain and increase system reliability.
(e)In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds.  As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million, representing estimated rental compensation for the first quarter of 2010 and prior years, including interest.  The portion of the total charge recorded to "Other operation and maintenance" on the Statement of Income totaled $49 million.  In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter.  In June 2011, the U.S. Supreme Court granted PPL Montana's petition.  In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's decision.  As a result in 2011, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $75 million was credited to "Other operation and maintenance" on the Statement of Income.
(f)2012 compared with 2011 was higher primarily due to $11 million of higher payroll-related costs, $7 million of higher project costs and $7 million of higher costs from the refueling outage.  2011 compared with 2010 was higher primarily due to $11 million of higher payroll-related costs, $10 million of higher outage costs and $8 million of higher costs from the refueling outage.
(g)2011 compared with 2010 was higher primarily due to $11 million of lower insurance proceeds.
(h)2012 compared with 2011 was higher primarily due to plant outage costs of $13 million.  2011 compared with 2010 was higher primarily due to plant outage costs of $13 million.
(i)There are no comparable amounts in 2011 as the Ironwood Acquisition occurred in April 2012.
(j)2012 compared with 2011 was higher primarily due to higher payroll costs of $17 million in 2012 for PPL Electric due to less project costs being capitalized.
(k)2011 compared with 2010 was higher primarily due to SMGT filing for protection under Chapter 11 of the U.S. Bankruptcy Code, $11 million of damages billed to SMGT were fully reserved.
(l)Both periods were higher due to higher pension costs resulting from increased amortization of actuarial losses.
(m)Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results.  The increase in 2012 compared with 2011 was partially due to four additional months of expense in 2012 of $86 million.  The comparable eight month period was $171 million lower in 2012 compared to 2011 due to $86 million of lower severance compensation, early retirement deficiency costs and outplacement services for employees separating from the WPD Midlands companies as a result of a reorganization to transition the WPD Midlands companies to the same operating structure as WPD (South West) and WPD (South Wales), $34 million of lower other acquisition related costs, and $26 million of lower pension expense.

Depreciation

The increase (decrease) in depreciation was due to:
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  2012 vs. 2011 2011 vs. 2010
       
Additions to PP&E $ 65  $ 20 
LKE (a) (b)      285 
WPD Midlands (c)   55    95 
Ironwood Acquisition (Note 10)   17    
Other   3    4 
Total $ 140  $ 404 

(a)For 2011 compared with 2010, includes $32 million of depreciation expense related to TC2, which began to dispatch in January 2011.
(b)2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results.
(c)Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results.  The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $49 million.

Taxes, Other Than Income

The increase (decrease) in taxes, other than income was due to:

   2012 vs. 2011 2011 vs. 2010
        
State gross receipts tax (a) $ (4) $ (5)
Domestic property tax expense (b)   14    (10)
Domestic sales and use tax      (2)
State capital stock tax (c)   (11)   11 
LKE (d)      35 
WPD Midlands (e)   33    60 
Other   8    (1)
Total $ 40  $ 88 

(a)The decrease in 2012 compared with 2011 was primarily due to a decrease in taxable electricity revenue.  The decrease in 2011 compared with 2010 was primarily due to a decrease in electricity revenue as customers chose alternative suppliers in 2010.  This tax is included in "Unregulated Gross Energy Margins" and "Pennsylvania Gross Delivery Margins" above.
(b)The increase in 2012 compared with 2011 is primarily due to the fully amortized PURTA refund that was refunded to the customers in 2011 pursuant to PUC regulations.  The decrease in 2011 compared with 2010 was primarily due to the amortization of the PURTA refund.  This tax is included in "Pennsylvania Gross Delivery Margins" above.
(c)The decrease in 2012 compared to 2011 was due to changes in the statutory rate from the prior year.  The increase in 2011 compared with 2010 was due in part to the expiration of the Keystone Opportunity Zone credit in 2010 and an agreed to change in a capital stock filing position with the state.
(d)2011 compared with 2010 was not comparable as 2010 includes two months of LKE's results.
(e)Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results.  The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $30 million.

Other Income (Expense) - net      
       
The increase (decrease) in other income (expense) - net was due to:
       
  2012 vs. 2011 2011 vs. 2010
       
Change in the fair value of economic foreign currency exchange contracts (Note 19) $ (62) $ 7 
Net hedge gains associated with the 2011 Bridge Facility (a)   (55)   55 
Foreign currency loss on 2011 Bridge Facility (b)   57    (57)
Gain on redemption of debt (c)   (22)   22 
Cash flow hedges (d)      29 
WPD Midlands acquisition-related adjustments in 2011 (Note 10)   55    (55)
LKE acquisition-related adjustments in 2010 (Note 10)      31 
Losses from equity method investments   (9)   (1)
Other   (7)   4 
Total $ (43) $ 35 

(a)Represents a gain on foreign currency contracts in 2011 that hedged the repayment of the 2011 Bridge Facility borrowing.
(b)Represents a foreign currency loss in 2011 related to the repayment of the 2011 Bridge Facility borrowing.
(c)In July 2011, as a result of PPL Electric's redemption of 7.125% Senior Secured Bonds due 2013, PPL recorded a gain on the accelerated amortization of the fair value adjustment to the debt recorded in connection with previously settled fair value hedges.
(d)Represents losses reclassified from AOCI into earnings in 2010 associated with discontinued hedges at PPL for debt that had been planned to be issued by PPL Energy Supply.  As a result of the expected net proceeds from the sale of certain non-core generation facilities, coupled with the monetization of full-requirement sales contracts, the debt issuance was no longer needed.

Other-Than-Temporary Impairments

Primarily due to a $25 million pre-tax impairment of the EEI investment, other-than-temporary impairments increased by $21 million in 2012 compared with 2011.  See Notes 1 and 18 to the Financial Statements for additional information.
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Interest Expense

The increase (decrease) in interest expense was due to:

   2012 vs. 2011 2011 vs. 2010
        
2011 Bridge Facility costs related to the acquisition of WPD Midlands (Notes 7 and 10) $ (44) $ 44 
2010 Bridge Facility costs related to the acquisition of LKE (Notes 7 and 10)      (80)
2010 Equity Units (a)   (2)   28 
2011 Equity Units (b)   12    34 
Short-term debt interest expense (c)   (12)   11 
Interest expense on the March 2010 WPD (South Wales) and WPD (South West) debt issuance      11 
Inflation adjustment on U.K. Index-linked Senior Unsecured Notes   (12)   5 
LKE (d)      126 
WPD Midlands (e)   80    154 
Ironwood Acquisition (Note 10)   12    
Hedging activities and ineffectiveness   29    11 
Capitalized interest (f)   (6)   (17)
Montana hydroelectric litigation (g)   10    (20)
Other   (4)   (2)
Total $ 63  $ 305 

(a)Interest related to the issuance in June 2010 to support the LKE acquisition.
(b)Interest related to the issuance in April 2011 to support the WPD Midlands acquisition.
(c)2012 compared with 2011 was lower primarily due to lower interest rates on 2012 short-term borrowings coupled with lower fees on credit facilities.  2011 compared with 2010 was higher primarily due to increased borrowings in 2011 and an increase in commitment fees on credit facilities.
(d)2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results.
(e)Amounts in each period are not comparable as 2011 includes eight months of WPD Midlands' results.  The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $74 million.
(f)Includes AFUDC.
(g)In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds.  In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter.  In 2011 and 2010, PPL Montana, recorded $4 million and $10 million of interest expense on the rental compensation covered by the court decision.  In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion.  As a result, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $14 million was credited to "Interest Expense" on the Statement of Income.

Income Taxes

The increase (decrease) in income taxes was due to:

   2012 vs. 2011 2011 vs. 2010
        
Higher (lower) pre-tax book income $ (296) $ 168 
State valuation allowance adjustments (a)   (23)   101 
State deferred tax rate change (b)   7    (26)
Domestic manufacturing deduction (c)      11 
Federal and state tax reserve adjustments (d)   (40)   99 
Federal and state tax return adjustments (e)   33    (14)
U.S. income tax on foreign earnings net of foreign tax credit (f)   57    (59)
U.K. Finance Act adjustments (g)   2    (16)
Foreign valuation allowance adjustments (h)   (147)   (68)
Foreign tax reserve adjustments (h)   134    (141)
U.K. capital loss benefit (h)      261 
Foreign tax return adjustments   (6)   
Health Care Reform      (8)
LKE (i)      125 
Depreciation not normalized (a)   9    (14)
WPD Midlands (j)   146    (2)
Net operating loss carryforward adjustments (k)   (9)   
Other   (13)   11 
Total $ (146) $ 428 

(a)During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes.  The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes.  Due to the decrease in projected taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL recorded a $43 million state deferred income tax expense related to deferred tax valuation allowances during 2011.
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Additionally, the 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.  The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012.  The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years.  PPL's tax deduction for 100% bonus regulated tax depreciation was significantly lower in 2012 than in 2011.

Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010.  Based on the projected revenue increase related to the expiration of the generation rate caps in 2010, PPL recorded a $72 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances related to the future projections of taxable income over the remaining carryforward period of the net operating losses during 2010.
(b)Changes in state apportionment resulted in reductions to the future estimated state tax rate at December 31, 2012 and 2011.  PPL recorded a $19 million deferred tax benefit in 2012 and a $26 million deferred tax benefit in 2011 related to its state deferred tax liabilities.
(c)In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property.  The increased tax depreciation eliminated the tax benefit related to the domestic manufacturing deduction in 2012 and 2011.
(d)In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD.  PPL filed its federal income tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable.  In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes.  As a result and with the finalization of other issues, PPL recorded a $42 million tax benefit in 2010.  In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit).  In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision, holding that the U.K. WPT is not a creditable tax.  As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011.  In February 2012, PPL filed a petition for rehearing of the Third Circuit's opinion.  In March 2012, the Third Circuit denied PPL's petition.  In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company.  In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion.  The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013.  PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.

In 2010, the Tax Court ruled in PPL's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years.  As a result, PPL recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes during 2010.

(e)During 2012, PPL recorded $16 million in federal and state income tax expense related to the filing of the 2011 federal and state income tax returns.  Of this amount, $5 million relates to the reversal of prior years' state income tax benefits related to regulated depreciation.  PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year.  In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets.  The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes.  PPL adopted the safe harbor method with the filing of its 2011 federal income tax return.

During 2011, PPL recorded $17 million in federal and state tax benefits related to the filing of the 2010 federal and state income tax returns.  Of this amount, $7 million in tax benefits related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts and $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated state tax depreciation.
(f)During 2012, PPL recorded a $23 million adjustment to federal income tax expense related to the recalculation of 2010 U.K. earnings and profits.

During 2011, PPL recorded a $28 million federal income tax benefit related to U.K. pension contributions.

During 2010, PPL recorded additional U.S. income tax expense primarily resulting from increased taxable dividends.
(g)The U.K.'s Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013.  As a result, PPL reduced its net deferred tax liabilities and recognized a $75 million deferred tax benefit in 2012 related to both rate decreases.  WPD Midlands' portion of the deferred tax benefit is $43 million.

The U.K.'s Finance Act of 2011, enacted in July 2011, reduced the U.K. statutory income tax rate from 27% to 26% retroactive to April 1, 2011 and from 26% to 25% effective April 1, 2012.  As a result, PPL reduced its net deferred tax liabilities and recognized a $69 million deferred tax benefit in 2011 related to both rate decreases. WPD Midlands' portion of the deferred tax benefit is $35 million.
The U.K.'s Finance Act of 2010, enacted in July 2010, reduced the U.K. statutory income tax rate from 28% to 27% effective April 1, 2011.  As a result, PPL reduced its net deferred tax liabilities and recognized an $18 million deferred tax benefit in 2010.
(h)During 2012, PPL recorded a $5 million tax benefit following resolution of a U.K. tax issue related to interest expense.

During 2011, WPD reached an agreement with the HMRC related to the amount of the capital losses that resulted from prior years' restructuring in the U.K. and recorded a $147 million foreign tax benefit for the reversal of tax reserves related to the capital losses.  Additionally, WPD recorded a $147 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.

During 2010, PPL recorded a $261 million foreign tax benefit in conjunction with losses resulting from restructuring in the U.K.  A portion of these losses offset tax on a deferred gain from a prior year sale of WPD's supply business.  WPD recorded a $215 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.
(i)2011 compared with 2010 was not comparable as 2010 includes two months of LKE's results.
(j)Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results.  The increase in 2012 compared with 2011 was primarily due to higher pre-tax book income.
(k)During 2012, PPL recorded adjustments to deferred taxes related to net operating loss carryforwards of LKE based on income tax return adjustments.
See Note 5 to the Financial Statements for additional information on income taxes.

Discontinued Operations

Operating Income (Loss) from Discontinued Operations (net of income taxes) decreased by $8 million in 2012 compared with 2011 primarily due to an adjustment recorded in 2012 to a liability for indemnifications related to the termination of the WKE lease in 2009.

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Income (Loss) from Discontinued Operations (net of income taxes) increased by $19 million in 2011 compared with 2010 primarily due to after-tax impairment charges recorded in 2010 totaling $62 million related to assets associated with certain non-core generation facilities sold in 2011 that were written down to their estimated fair value (less cost to sell).  The impacts of these charges were offset by the net results of certain other discontinued operations.

See Note 9 to the Financial Statements for additional information.

Noncontrolling Interests

"Net Income Attributable to Noncontrolling Interests" decreased by $12 million in 2012 compared with 2011.  The decrease is primarily due to PPL Electric's June 2012 redemption of all 2.5 million shares of its preference stock.

Financial Condition

Liquidity and Capital Resources

PPL expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances.  Additionally, subject to market conditions, PPL currently plans to access capital markets in 2013.

PPL's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:

·changes in electricity, fuel and other commodity prices;
·operational and credit risks associated with selling and marketing products in the wholesale power markets;
·potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate PPL's risk exposure to adverse changes in electricity and fuel prices, interest rates, foreign currency exchange rates and counterparty credit;
·unusual or extreme weather that may damage PPL's transmission and distribution facilities or affect energy sales to customers;
·reliance on transmission and distribution facilities that PPL does not own or control to deliver its electricity and natural gas;
·unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·costs of compliance with existing and new environmental laws and with new security and safety requirements for nuclear facilities;
·any adverse outcome of legal proceedings and investigations with respect to PPL's current and past business activities;
·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·a downgrade in PPL's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt.

See "Item 1A. Risk Factors" for further discussion of risks and uncertainties that could affect PPL's cash flows.

At December 31, PPL had the following:

  2012  2011  2010 
          
Cash and cash equivalents $ 901  $ 1,202  $ 925 
Short-term investments (a)      16    163 
  $ 901  $ 1,218  $ 1,088 
Short-term debt $ 652  $ 578  $ 694 

(a)2010 amount represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky on behalf of LG&E that were subsequently purchased by LG&E.  Such bonds were remarketed to unaffiliated investors in January 2011.  See Note 23 to the Financial Statements for further discussion.
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At December 31, 2012, $225 million of cash and cash equivalents were denominated in GBP.  If these amounts would be remitted as dividends, PPL may be subject to additional U.S. taxes, net of allowable foreign tax credits.  Historically, dividends paid by foreign subsidiaries have been limited to distributions of the current year's earnings.  See Note 5 to the Financial Statements for additional information on undistributed earnings of WPD.

The changes in PPL's cash and cash equivalents position for the years ended December 31 resulted from:

  2012  2011  2010 
          
Net cash provided by (used in) operating activities $ 2,764  $ 2,507  $ 2,033 
Net cash provided by (used in) investing activities   (3,123)   (7,952)   (8,229)
Net cash provided by (used in) financing activities   48    5,767    6,307 
Effect of exchange rates on cash and cash equivalents   10    (45)   13 
Net Increase (Decrease) in Cash and Cash Equivalents $ (301) $ 277  $ 124 

Operating Activities

Net cash provided by operating activities increased by 10%, or $257 million, in 2012 compared with 2011.  The increase was the net effect of:

·an increase of $339 million in net income, when adjusted for non-cash components; and
·a decrease of $60 million in defined benefit plan funding; partially offset by
·changes in working capital of $178 million, primarily driven by changes in prepayments and net regulatory assets/liabilities offset by the changes in counterparty collateral.

Included in the above amounts is the impact of having an additional four months of WPD Midlands operations in 2012.  WPD Midlands' cash from operating activities increased by $190 million in 2012 compared with 2011.

Net cash provided by operating activities increased by 23%, or $474 million, in 2011 compared with 2010.  The increase was the net effect of:

·operating cash provided by LKE, $743 million, and WPD Midlands, $234 million;
·cash from components of working capital, $435 million, primarily related to changes in prepaid income and gross receipts taxes; partially offset by
·      reduction in cash from counter party collateral, $172 million:
·      lower gross energy margins, $240 million after-tax:
·proceeds from monetizing certain full-requirement sales contracts in 2010, $249 million:
·higher interest payments of $44 million; and
·increases in other operating outflows of $233 million (including $90 million of higher operation and maintenance expenses and defined benefits funding).

A significant portion of PPL's Supply segment operating cash flows is derived from its competitive baseload generation business activities.  PPL employs a formal hedging program for its baseload generation fleet, the primary objective of which is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term.  See Note 19 to the Financial Statements for further discussion.  Despite PPL's hedging practices, future cash flows from operating activities from its Supply segment are influenced by commodity prices and, therefore, will fluctuate from period to period.

PPL's contracts for the sale and purchase of electricity and fuel often require cash collateral or other credit enhancements, or reductions or terminations of a portion of the entire contract through cash settlement,period were, in the event of a downgrade of PPL's or its subsidiaries' credit ratings or adverse changes in market prices.  For example, in addition to limiting its trading ability, if PPL's or its subsidiaries' ratings were lowered to below "investment grade" and there was a 10% adverse movement in energy prices, PPL estimates that, based on its December 31, 2012 positions, it would have been required to post additional collateral of approximately $438 million with respect to electricity and fuel contracts.  PPL has in place risk management programs that are designed to monitor and manage its exposure to volatility of cash flows related to changes in energy and fuel prices, interest rates, foreign currency exchange rates, counterparty credit quality and the operating performance of its generating units.
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Investing Activities

The primary use of cash in investing activities in 2012 was for capital expenditures.  In 2011, the primary uses of cash in investing activities were for the acquisition of WPD Midlands and capital expenditures.  In 2010, the primary uses of cash in investing activities were for the acquisition of LKE and capital expenditures.  See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.

Net cash used in investing activities was $3.1 billion in 2012 compared with $7.9 billion in 2011.  Excluding the impact of cash used for the 2011 acquisition of WPD Midlands, net cash used in investing activities increased by $934 million in 2012 compared with 2011.  This increase reflects $618 million of higher capital expenditures, $381 million less in asset sale proceeds (2011 sale of certain non-core generation facilities) and a $143 million reduction in proceeds from the sale of certain investments (other than securities in the nuclear plant decommissioning trust funds) partially offset by a $239 million net change in restricted cash and cash equivalents.  See Note 9 to the Financial Statements for additional information on the sale of certain non-core generation facilities and Note 10 to the Financial Statements for additional information regarding the WPD Midlands acquisition.

Net cash used in investing activities was $7.9 billion in 2011 compared with $8.2 billion in 2010.  The 2011 amount includes the use of $5.8 billion of cash for the acquisition of WPD Midlands, while 2010 includes $6.8 billion for the acquisition of LKE.  See Note 10 to the Financial Statements for additional information regarding the acquisitions.  Excluding the impact of the acquisitions, net cash used in investing activities increased by $772 million in 2011 compared with 2010.  This increase reflects $890 million of higher capital expenditures and a $228 million net change in restricted cash, partially offset by $219 million of additional proceeds from the sale of certain businesses or facilities and $163 million of proceeds from the sale of investments, other than securities in the nuclear plant decommissioning trust funds.  PPL received proceeds of $381 million in 2011 from the sale of certain non-core generation facilities compared with proceeds of $162 million in 2010 from the sale of the Long Island generation business and certain Maine hydroelectric generation facilities.  See Note 9 to the Financial Statements for additional information on the sale of these businesses or facilities.

Financing Activities

Net cash provided by financing activities was $48 million in 2012 compared with $5.8 billion in 2011.  The decrease of $5.7 billion was primarily the result of lower net long-term debt issuances of $3.4 billion and less proceeds from the issuance of common stock of $2.2 billion.  Both of these decreases were primarily related to the 2011 acquisition of WPD Midlands.  The decrease also included $250 million paid to redeem a subsidiary's preference stock and $87 million of higher common stock dividends.  These decreases were partially offset by a $199 million net change in short-term debt.

Net cash provided by financing activities was $5.8 billion in 2011 compared with $6.3 billion in 2010, primarily as a result of issuance of long-term debt and equity relatedpart, attributable to the acquisition of WPD Midlands in 2011RJS Power, MACH Gen and the acquisition of LKE in 2010.  The decrease of $540 million was primarily the result of lower net long-term debt issuances of $87 million, lower proceeds from the issuance of common stock of $144 million, $180 million of higher common stock dividends and a $195 million decrease in net, short-term debt.

See "Forecasted Sources of Cash" for a discussion of PPL's plans to issue debt and equity securities, as well as a discussion of credit facility capacity available to PPL.  Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.

Long-term Debt and Equity Securities

The long-term debt and equity securities activity for the year ended December 31, 2012 was:
          Equity
    Debt Issuances
    Issuances (a) Retirements (Redemptions)
            
PPL Capital Funding Senior Notes (b) $ 798  $ (99)   
PPL Electric First Mortgage Bonds   249       
WPD (East Midlands) Senior Notes   176       
PPL Electric preference stock (c)       $ (250)
  Total Cash Flow Impact $ 1,223  $ (99) $ (250)
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          Equity
    Debt Issuances
    Issuances (a) Retirements (Redemptions)
          
Assumed through consolidation - Ironwood Acquisition (d) $ 258       
Non-cash Exchanges:         
 LKE Senior Notes (e) $ 250  $ (250)   
            
Net Increase (decrease) $ 1,382     $ (250)

(a)Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs.
(b)Senior unsecured notes of $99 million were redeemed at par prior to their 2047 maturity date.
(c)In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share, which was included in "Noncontrolling Interests" on the 2011 Balance Sheet.
(d)Includes $24 million of fair value adjustments resulting from the purchase price allocation.  See Note 10 to the Financial Statements for additional information on the acquisition.
(e)In June 2012, LKE completed an exchange of all its outstanding 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered with the SEC.

In addition to the above, in April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock.  In conjunction withseveral items that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.

In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL common stock.  Settlement of these initial forward sale agreements will occur no later than April 2013.  As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the additional 591 thousand shares of PPL common stock.  Settlement of the subsequent forward sale agreements will occur no later than July 2013.  Upon any physical settlement of any forward sale agreement, PPL will issue and deliver to the forward counterparties shares of its common stock in exchange for cash proceeds per share equal to the forward sale price.  The forward sale price will be calculated based on an initial forward price of $27.02 per share reduced during the period the contracts are outstanding as specified in the forward sale agreements.  PPL may, in certain circumstances, elect cash settlement or net share settlement for all or a portion of its rights or obligations under the forward sale agreements.

PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements.  PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.

The forward sale agreements are classified as equity transactions.  As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements.  Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method.

See Note 7 to the Financial Statements for additional information about long-term debt and equity securities.

Forecasted Sources of Cash

PPL expects to continue to have sufficient sources of liquidity available in the near term, including cash flows from operations, various credit facilities, commercial paper issuances and operating leases.  Additionally, subject to market conditions, PPL currently plans to access capital markets in 2013.

Credit Facilities

At December 31, 2012, PPL's total committed borrowing capacity under credit facilities and the use of this borrowing capacity were:

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         Letters of   
         Credit   
         Issued   
         and   
       Commercial  
   Committed   Paper Unused
   Capacity Borrowed Backstop Capacity
          
PPL Energy Supply Credit Facilities (a) $ 3,200     $ 631  $ 2,569 
PPL Electric Credit Facilities (a) (b)   400       1    399 
LG&E Credit Facility (a)   500       55    445 
KU Credit Facilities (a)   598       268    330 
 Total Domestic Credit Facilities (c) (f) $ 4,698     $ 955  $ 3,743 
              
PPL WW Credit Facility (d) (e) £ 150  £ 106   n/a £ 44 
WPD (South West) Credit Facility (e)   245      n/a   245 
WPD (East Midlands) Credit Facility (e) (g)   300          300 
WPD (West Midlands) Credit Facility (e) (g)   300          300 
 Total WPD Credit Facilities (h) (f) £ 995  £ 106     £ 889 

(a)The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 65% for PPL Energy Supply and 70% for PPL Electric, LG&E and KU, as calculated in accordance with the facility, and other customary covenants.  See Note 7 to the Financial Statements for additional information regarding these credit facilities.
(b)Includes a $100 million credit facility related to an asset-backed commercial paper program through which PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis.  The subsidiary pledges these assets to secure loans of up to an aggregate of $100 million from a commercial paper conduit sponsored by a financial institution.  At December 31, 2012, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under the facility was $100 million.
(c)The commitments under PPL's domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 9% of the total committed capacity.
(d)In December 2012, the PPL WW credit facility was subsequently replaced with a credit facility expiring in December 2016 and the capacity was increased to £210 million.
(e)The facilities contain financial covenants that require the company to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, calculated in accordance with the credit facility.
(f)Each company pays customary fees under its respective syndicated credit facility, as does KU under its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
(g)Under the facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing.
(h)The total amount borrowed at December 31, 2012 was a USD-denominated borrowing of $171 million, which equated to £106 million at the time of borrowing and bore interest at 0.8452%.  At December 31, 2012, the unused capacity of WPD's committed credit facilities was approximately $1.4 billion.

The commitments under WPD's credit facilities are provided by a diverse bank group with no one bank providing more than 16% of the total committed capacity.

In addition to the financial covenants noted in the table above, the credit agreements governing the above credit facilities contain various other covenants.  Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements.  PPL monitors compliance with the covenants on a regular basis.  At December 31, 2012, PPL was in compliance with these covenants.  At this time, PPLmanagement believes that these covenants and other borrowing conditions will not limit access to these funding sources.

See Note 7 to the Financial Statements for further discussion of PPL's credit facilities.

Commercial Paper

PPL Energy Supply maintains a $750 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility.  At December 31, 2012, PPL Energy Supply had $356 million of commercial paper outstanding at a weighted-average interest rate of 0.50%.

PPL Electric maintains a $300 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are currently supported by PPL Electric's Syndicated Credit Facility.  PPL Electric had no commercial paper outstanding at December 31, 2012.
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In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide additional financing sources to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by LG&E's and KU's Syndicated Credit Facilities.  At December 31, 2012, LG&E and KU had $55 million and $70 million of commercial paper outstanding at a weighted average interest rate, for each, of 0.42%.

Operating Leases

PPL and its subsidiaries also have available funding sources that are provided through operating leases.  PPL's subsidiaries lease office space, land, buildings and certain equipment.  These leasing structures provide PPL additional operating and financing flexibility.  The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.

PPL, through its subsidiary PPL Montana, leases a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3, under four 36-year, non-cancelable operating leases.  These operating leases are not recorded on PPL's Balance Sheets.  The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assetsindicative of ongoing operations. See "EBITDA and declare dividends.  See Note 7 to the Financial Statements for a discussion of other dividend restrictions related to PPL subsidiaries.

See Note 11 to the Financial Statements for further discussion of the operating leases.

Long-term Debt and Equity Securities

PPL and its subsidiaries currently plan to incur, subject to market conditions, approximately $2.0 billion of long-term indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.  In addition during 2013, two events will occur related to the components of the 2010 Equity Units.  PPL will receive proceeds of $1.150 billion through the issuance of PPL common stock to settle the 2010 Purchase Contracts; and PPL Capital Funding expects to remarket the 4.625% Junior Subordinated Notes due 2018.  See Note 7 to the Financial Statements for additional information.

In addition, PPL currently plans to issue new shares of common stock in 2013 in an aggregate amount up to $350 million under its forward contracts (see Note 7 to the Financial Statements for more information), DRIP and various employee stock-based compensation and other plans.

Forecasted Uses of Cash

In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, PPL currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of debt securities.

Capital Expenditures

The tableAdjusted EBITDA" below shows PPL's current capital expenditure projections for the years 2013 through 2017.

    Projected
    2013  2014  2015  2016  2017 
Construction expenditures (a) (b)               
 Generating facilities $ 814  $ 500  $ 514  $ 717  $ 831 
 Distribution facilities   1,780    1,654    1,712    1,711    1,763 
 Transmission facilities   723    599    457    413    390 
 Environmental   750    812    536    312    128 
 Other   139    126    117    105    99 
  Total Construction Expenditures   4,206    3,691    3,336    3,258    3,211 
Nuclear fuel   152    145    153    158    162 
  Total Capital Expenditures $ 4,358  $ 3,836  $ 3,489  $ 3,416  $ 3,373 

(a)Construction expenditures include capitalized interest and AFUDC, which are expected to total approximately $160 million for the years 2013 through 2017.
(b)Includes expenditures for certain intangible assets.


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PPL's capital expenditure projections for the years 2013 through 2017 total approximately $18.5 billion.  Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.  For the years presented, this table includes projected costs related to the planned 793 MW of incremental capacity increases for both PPL Energy Supply and LKE, PPL Electric's asset optimization program to replace aging transmission and distribution assets and the PJM-approved regional transmission line expansion project.  This table also includes LKE's environmental projects related to existing and proposed EPA compliance standards (actual costs may be significantly lower or higher depending on the final requirements; environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism).  See Notes 6 and 8 to the Financial Statements for information on LG&E's and KU's ECR plans and the PJM-approved regional transmission line expansion project and the other significant development projects.

PPL plans to fund its capital expenditures in 2013 with cash from operations and proceeds from the issuance of common stock and debt securities.

Contractual Obligations

PPL has assumed various financial obligations and commitments in the ordinary course of conducting its business.  At December 31, 2012, the estimated contractual cash obligations of PPL were:

   Total 2013  2014 - 2015 2016 - 2017 After 2017
                 
Long-term Debt (a) $ 19,435  $ 751  $ 1,645  $ 946  $ 16,093 
Interest on Long-term Debt (b)   14,276    932    1,704    1,530    10,110 
Operating Leases (c)   507    109    191    58    149 
Purchase Obligations (d)   8,770    2,642    2,847    1,604    1,677 
Other Long-term Liabilities               
 Reflected on the Balance               
 Sheet under GAAP (e) (f)   607    560    47       
Total Contractual Cash Obligations $ 43,595  $ 4,994  $ 6,434  $ 4,138  $ 28,029 

(a)Reflects principal maturities only based on stated maturity dates, except for PPL Energy Supply's 5.70% REset Put Securities (REPS).  See Note 7 to the Financial Statements for a discussion of the remarketing feature related to the REPS, as well as discussion of variable-rate remarketable bonds issued on behalf of PPL Energy Supply, LG&E and KU.  PPL does not have any significant capital lease obligations.
(b)Assumes interest payments through stated maturity, except for the REPS, for which interest is reflected to the put date.  The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated and payments denominated in British pounds sterling have been translated to U.S. dollars at a current foreign currency exchange rate.
(c)See Note 11 to the Financial Statements for additional information.
(d)The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.  Primarily includes PPL's purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the Capital Expenditures table presented above.  Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented.
(e)The amounts include WPD's contractual deficit pension funding requirements arising from actuarial valuations performed in March 2010 and June 2011.  The U.K. electricity regulator currently allows a recovery of a substantial portion of the contributions relating to the plan deficit; however, WPD cannot be certain that this will continue beyond the current review period, which extends to March 31, 2015.  The amounts also include contributions made or committed to be made for 2013 for PPL's and LKE's U.S. pension plans.  See Note 13 to the Financial Statements for a discussion of expected contributions.

Also included in the amounts are contract adjustment payments related to the Purchase Contract component of the Equity Units.  See Note 7 to the Financial Statements for additional information on the Equity Units.
(f)At December 31, 2012, total unrecognized tax benefits of $92 million were excluded from this table as PPL cannot reasonably estimate the amount and period of future payments.  See Note 5 to the Financial Statements for additional information.

Dividends

PPL views dividends as an integral component of shareowner return and expects to continue to pay dividends in amounts that are within the context of maintaining a capitalization structure that supports investment grade credit ratings.  In 2012, PPL's Board of Directors declared an increase to its quarterly dividend on its common stock to 36.0 cents per share (equivalent to $1.44 per share per annum).  In February 2013, PPL's Board of Directors declared an increase to its quarterly dividend on its common stock to 36.75 cents per share (equivalent to $1.47 per share per annum).  Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other relevant factors at the time.  As discussed in Note 7 to the Financial Statements, subject to certain exceptions, PPL may not declare or pay any cash dividend on its common stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067, its 4.625% Junior Subordinated Notes due 2018, or its 4.32% Junior Subordinated Notes due 2019 or until deferred contract adjustment payments on PPL's Purchase Contracts have been paid.  No such deferrals have occurred or are currently anticipated.
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See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for PPL subsidiaries.

Purchase or Redemption of Debt Securities

PPL will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.

Rating Agency Actions

Moody's, S&P and Fitch periodically review the credit ratings on the debt of PPL and its subsidiaries.  Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.

A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues.  The credit ratings of PPL and its subsidiaries are based on information provided by PPL and other sources.  The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL or its subsidiaries.  Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.  The credit ratings of PPL and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.

The following table sets forth PPL's and its subsidiaries' security credit ratings as of December 31, 2012.

Senior UnsecuredSenior SecuredCommercial Paper
IssuerMoody'sS&PFitchMoody'sS&PFitchMoody'sS&PFitch
PPL Energy SupplyBaa2BBBBBBP-2A-2F-2
PPL Capital FundingBaa3BBB-BBB
PPL ElectricA3A-A-P-2A-2F-2
PPL IronwoodB2B
LKEBaa2BBB-BBB+
LG&EAA2A-A+P-2A-2F-2
KUAA2A-A+P-2A-2F-2
PPL WEMBaa3BBB-
WPD (East Midlands)Baa1BBB
WPD (West Midlands)Baa1BBB
PPL WWBaa3BBB-BBB
WPD (South Wales)Baa1BBBA-
WPD (South West)Baa1BBBA-P-2

A downgrade in PPL's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets.  PPL and its subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.

In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL and its subsidiaries in 2012.

In January 2012, S&P affirmed its rating and revised its outlook, from positive to stable, for PPL Montana's Pass Through Certificates due 2020.

In February 2012, Fitch assigned ratings to the two newly established commercial paper programs for LG&E and KU.

In March 2012, Moody's affirmed the following ratings:
·the long-term ratings of the First Mortgage Bonds for LG&E and KU;
·the issuer ratings for LG&E and KU; and

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·the bank loan ratings for LG&E and KU.

Also in March 2012, Moody's and S&P each assigned short-term ratings to the two newly established commercial paper programs for LG&E and KU.

In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A and 2007 Series B pollution control bonds.

Following the announcement of the then-pending acquisition of AES Ironwood, L.L.C. in February 2012, the rating agencies took the following actions:
·In March 2012, Moody's placed AES Ironwood, L.L.C.'s senior secured bonds under review for possible ratings upgrade.
·In April 2012, S&P affirmed the rating of AES Ironwood, L.L.C.'s senior secured bonds.

In May 2012, Fitch downgraded its rating, from BBB to BBB- and revised its outlook, from negative to stable, for PPL Montana's Pass Through Certificates due 2020.

In June 2012, Fitch assigned a rating and outlook to PPL Capital Funding's $400 million of 4.20% Senior Notes.

In August 2012, Fitch assigned a rating and outlook to PPL Electric's $250 million First Mortgage Bonds.

In August 2012, S&P and Moody's assigned a rating to PPL Electric's $250 million First Mortgage Bonds.

In October 2012, Moody's, S&P and Fitch assigned a rating to PPL Capital Funding's $400 million of 3.50% Senior Notes.

In November 2012, Fitch affirmed the long-term issuer default rating and senior unsecured rating of PPL WW, WPD (South Wales) and WPD (South West).

In November 2012, S&P revised its outlook, from stable to negative, for PPL Montana's Pass Through Certificates due 2020.

In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.

In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlooks for PPL, PPL Capital Funding, PPL Electric, LKE, LG&E and KU.

In December 2012, Fitch affirmed the issuer default rating, individual security rating and revised the outlook, from stable to negative, for PPL Energy Supply.
In February 2013, Moody's upgraded its rating, from Ba1 to B2, and revised the outlook from under review to stable for PPL Ironwood.

Ratings Triggers

As discussed in Note 7 to the Financial Statements, certain of WPD's senior unsecured notes may be put by the holders back to the issuer for redemption if the long-term credit ratings assigned to the notes are withdrawn by any of the rating agencies (Moody's, S&P, or Fitch) or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event.  A restructuring event includes the loss of, or a material adverse change to, the distribution licenses under which WPD (East Midlands), WPD (South West), WPD (South Wales) and WPD (West Midlands) operate and would be a trigger event in that company.  These notes totaled £3.3 billion (approximately $5.3 billion) nominal value at December 31, 2012.

PPL and PPL Energy Supply have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, tolling agreements, and interest rate and foreign currency instruments, which contain provisions that require PPL and PPL Energy Supply to post additional collateral, or permit the counterparty to terminate the contract, if PPL's or PPL Energy Supply's credit rating were to fall below investment grade.  See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012.  At December 31, 2012, if PPL's and its subsidiaries' credit ratings had been below investment grade, PPL would have been required to prepay or post an additional $501 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate and foreign currency contracts.
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Guarantees for Subsidiaries

PPL guarantees certain consolidated affiliate financing arrangements that enable certain transactions.  Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, require early maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions.  At this time, PPL believes that these covenants will not limit access to relevant funding sources.  See Note 15 to the Financial Statements for additional information about guarantees.

Off-Balance Sheet Arrangements

PPL has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party.  See Note 15 to the Financial Statements for a discussion of these agreements.

Risk Management - Energy Marketing & Trading and Other

Market Risk

See Notes 1, 18, and 19 to the Financial Statements for information about PPL's riskitems management objectives, valuation techniques and accounting designations.

The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions.  Actual future results may differ materially from those presented.  These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.

Commodity Price Risk (Non-trading)

PPL segregates its non-trading activities into two categories:  hedge activity and economic activity.  Transactions that are accounted for as hedge activity qualify for hedge accounting treatment.  The economic activity category includes transactions that address a specific risk, but were not eligible for hedge accounting or for which hedge accounting was not elected.  This activity includes the changes in fair value of positions used to hedge a portion of the economic value of PPL's competitive generation assets and full-requirement sales and retail contracts.  This economic activity is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power).  Although they do not receive hedge accounting treatment, these transactions are considered non-trading activity.  The net fair value of economic positions at December 31, 2012 and 2011 was a net asset/(liability) of $346 million and $(63) million.  See Note 19 to the Financial Statements for additional information.

To hedge the impact of market price volatility on PPL's energy-related assets, liabilities and other contractual arrangements, PPL both sells and purchases physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enters into financial exchange-traded and over-the-counter contracts.  PPL's non-trading commodity derivative contracts range in maturity through 2019.

The following table sets forth the changes in the net fair value of non-trading commodity derivative contracts at December 31, 2012.  See Notes 18 and 19 to the Financial Statements for additional information.

   Gains (Losses)
   2012  2011 
        
Fair value of contracts outstanding at the beginning of the period $ 1,082  $ 947 
Contracts realized or otherwise settled during the period   (1,005)   (517)
Fair value of new contracts entered into during the period (a)   7    13 
Other changes in fair value   389    639 
Fair value of contracts outstanding at the end of the period $ 473  $ 1,082 

(a)Represents the fair value of contracts at the end of the quarter of their inception.

The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2012 based on the level of observability of the information used to determine the fair value.

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   Net Asset (Liability)
   Maturity       Maturity   
   Less Than Maturity Maturity in Excess Total Fair
   1 Year 1-3 Years 4-5 Years of 5 Years Value
Source of Fair Value               
Prices based on significant observable inputs (Level 2) $ 452  $ 15  $ (20) $ 5  $ 452 
Prices based on significant unobservable inputs (Level 3)   8    10    3       21 
Fair value of contracts outstanding at the end of the period $ 460  $ 25  $ (17) $ 5  $ 473 

PPL sells electricity, capacity and related services and buys fuel on a forward basis to hedge the value of energy from its generation assets.  If PPL were unable to deliver firm capacity and energy or to accept the delivery of fuel under its agreements, under certain circumstances it could be required to pay liquidating damages.  These damages would be based on the difference between the market price and the contract price of the commodity.  Depending on price changes in the wholesale energy markets, such damages could be significant.  Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties (or their counterparties) with which it has energy contracts and other factors could affect PPL's ability to meet its obligations, or cause significant increases in the market price of replacement energy.  Although PPL attempts to mitigate these risks, there can be no assurance that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future.  In connection with its bankruptcy proceedings, a significant counterparty, SMGT, had been purchasing lower volumes of electricity than prescribed in the contract and effective April 1, 2012 the contract was terminated.  PPL cannot predict the prices or other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of this contract.  See Note 15 to the Financial Statements for additional information.

Commodity Price Risk (Trading)

PPL's trading commodity derivative contracts range in maturity through 2017.  The following table sets forth changes in the net fair value of trading commodity derivative contracts at December 31, 2012.  See Notes 18 and 19 to the Financial Statements for additional information.

  Gains (Losses)
  2012  2011 
       
Fair value of contracts outstanding at the beginning of the period $ (4) $ 4 
Contracts realized or otherwise settled during the period   20    (14)
Fair value of new contracts entered into during the period (a)   17    10 
Other changes in fair value   (4)   (4)
Fair value of contracts outstanding at the end of the period $ 29  $ (4)

(a)Represents the fair value of contracts at the end of the quarter of their inception.

The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2012 based on the level of observability of the information used to determine the fair value.

   Net Asset (Liability)
   Maturity       Maturity   
   Less Than Maturity Maturity in Excess Total Fair
   1 Year 1-3 Years 4-5 Years of 5 Years Value
Source of Fair Value               
Prices based on significant observable inputs (Level 2) $ 18  $ 10        $ 28 
Prices based on significant unobservable inputs (Level 3)   1             1 
Fair value of contracts outstanding at the end of the period $ 19  $ 10        $ 29 

VaR Models

A VaR model is utilized to measure commodity price risk in domestic gross energy margins for its non-trading and trading portfolios.  VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level.  VaR is calculated using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level.  Given the company's disciplined hedging program, the non-trading VaR exposure is expected to be limited in the short-term.  The VaR for portfolios using end-of-month results for the period was as follows.

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   Trading VaR Non-Trading VaR
   2012  2011  2012  2011 
95% Confidence Level, Five-Day Holding Period            
 Period End $ 2  $ 1  $ 12  $ 6 
 Average for the Period   3    3    10    5 
 High   8    6    12    7 
 Low   1    1    7    4 

The trading portfolio includes all proprietary trading positions, regardless of the delivery period.  All positions not considered proprietary trading are considered non-trading.  The non-trading portfolio includes the entire portfolio, including generation, with delivery periods through the next 12 months.  Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets.  The fair value of the non-trading and trading FTR positions was insignificant at December 31, 2012.

Interest Rate Risk

PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk.  PPL utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio, adjust the duration of its debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate.  Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL's debt portfolio due to changes in the absolute level of interest rates.

At December 31, 2012 and 2011, PPL's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.

PPL is also exposed to changes in the fair value of its domestic and international debt portfolios.  PPL estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $611 million, compared with $635 million at December 31, 2011.

PPL had the following interest rate hedges outstanding at December 31.

   2012  2011 
         Effect of a       Effect of a
     Fair Value, 10% Adverse   Fair Value, 10% Adverse
    Exposure Net - Asset Movement  Exposure Net - Asset Movement
   Hedged (Liability) (a) in Rates (b) Hedged (Liability) (a) in Rates (b)
Cash flow hedges                  
 Interest rate swaps (c) $ 1,165  $ (7) $ (34) $ 150  $ (3) $ (3)
 Cross-currency swaps (d)   1,262    10    (179)   1,262    22    (187)
Fair value hedges                  
 Interest rate swaps            99    4    
Economic hedges                  
 Interest rate swaps (e)   179    (58)   (3)   179    (60)   (4)

(a)Includes accrued interest, if applicable.
(b)Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.
(c)PPL utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments.  These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing.  While PPL is exposed to changes in the fair value of these instruments, any changes in the fair value of such cash flow hedges are recorded in equity or as regulatory assets or liabilities, if recoverable through regulated rates.  The changes in fair value of these instruments are then reclassified into earnings in the same period during which the item being hedged affects earnings.  Sensitivities represent a 10% adverse movement in interest rates.  The positions outstanding at December 31, 2012 mature through 2043.
(d)PPL utilizes cross-currency swaps to hedge the interest payments and principal of WPD's U.S. dollar-denominated senior notes.  While PPL is exposed to changes in the fair value of these instruments, any change in the fair value of these instruments is recorded in equity and reclassified into earnings in the same period during which the item being hedged affects earnings.  Sensitivities represent a 10% adverse movement in both interest rates and foreign currency exchange rates.  The positions outstanding at December 31, 2012 mature through 2028.
(e)PPL utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments.  These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing.  While PPL is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities.  Sensitivities represent a 10% adverse movement in interest rates.  The positions outstanding at December 31, 2012 mature through 2033.
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Foreign Currency Risk

PPL is exposed to foreign currency risk, primarily through investments in U.K. affiliates.  In addition, PPL's domestic operations may make purchases of equipment in currencies other than U.S. dollars.  See Note 1 to the Financial Statements for additional information regarding foreign currency translation.

PPL has adopted a foreign currency risk management program designed to hedge certain foreign currency exposures, including firm commitments, recognized assets or liabilities, anticipated transactions and net investments.  In addition, PPL enters into financial instruments to protect against foreign currency translation risk of expected earnings.

PPL had the following foreign currency hedges outstanding at December 31:

  2012  2011 
        Effect of a 10%       Effect of a 10%
     Fair Value, Adverse Movement    Fair Value, Adverse Movement
  Exposure Net - Asset in Foreign Currency Exposure Net - Asset in Foreign Currency
  Hedged (Liability) Exchange Rates (a) Hedged (Liability) Exchange Rates (a)
                   
Net investment hedges (b) £ 162  $ (2) $ (26) £ 92  $ 7  $ (13)
Economic hedges (c)   1,265    (42)   (192)   288    11    (37)

(a)Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability.
(b)To protect the value of a portion of its net investment in WPD, PPL executes forward contracts to sell GBP.  The positions outstanding at December 31, 2012 mature through 2013.  Excludes the amount of an intercompany loan classified as a net investment hedge.  See Note 19 to the Financial Statements for additional information.
(c)To economically hedge the translation of expected income denominated in GBP to U.S. dollars, PPL enters into a combination of average rate forwards and average rate options to sell GBP.  The forwards and options outstanding at December 31, 2012 mature through 2015.

NDT Funds - Securities Price Risk

In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the PPL Susquehanna nuclear plant (Susquehanna).  At December 31, 2012, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on PPL's Balance Sheet.  The mix of securities is designed to provide returns sufficient to fund Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs.  However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates.  PPL actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement.  At December 31, 2012, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $49 million reduction in the fair value of the trust assets, compared with $43 million at December 31, 2011.  See Notes 18 and 23 to the Financial Statements for additional information regarding the NDT funds.

Defined Benefit Plans - Securities Price Risk

See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on plan assets.

Credit Risk

Credit risk is the risk that PPL would incur a loss as a result of nonperformance by counterparties of their contractual obligations.  PPL maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk.  However, PPL has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies.  These concentrations may impact PPL's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
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PPL includes the effect of credit risk on its fair value measurements to reflect the probability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint).  In this case, PPL would have to sell into a lower-priced market or purchase in a higher-priced market.  When necessary, PPL records an allowance for doubtful accounts to reflect the probability that a counterparty will not pay for deliveries PPL has made but not yet billed, which are reflected in "Unbilled revenues" on the Balance Sheets.  PPL also has established a reserve with respect to certain receivables from SMGT, which is reflected in accounts receivable on the Balance Sheets.  See Note 15 to the Financial Statements for additional information.

In 2009, the PUC approved PPL Electric's PLR procurement plan for the period January 2011 through May 2013.  To date, PPL Electric has conducted all of its planned competitive solicitations.

Under the standard Supply Master Agreement (the Agreement) for the competitive solicitation process, PPL Electric requires all suppliers to post collateral if their credit exposure exceeds an established credit limit.  In the event a supplier defaults on its obligation, PPL Electric would be required to seek replacement power in the market.  All incremental costs incurred by PPL Electric would be recoverable from customers in future rates.  At December 31, 2012, most of the successful bidders under all of the solicitations had an investment grade credit rating from S&P, and were not required to post collateral under the Agreement.  A small portion of bidders were required to post collateral, which totaled less than $1 million, under the Agreement.  There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.

See "Overview" in this Item 7 and Notes 15, 16, 18 and 19 to the Financial Statements for additional information on the competitive solicitations, the Agreement, credit concentration and credit risk.

Foreign Currency Translation

The value of the British pound sterling fluctuates in relation to the U.S. dollar.  In 2012, changes in this exchange rate resulted in a foreign currency translation gain of $99 million, which primarily reflected a $181 million increase to PP&E offset by an increase of $82 million to net liabilities.  In 2011, changes in this exchange rate resulted in a foreign currency translation loss of $51 million, which primarily reflected a $69 million reduction to PP&E offset by a reduction of $18 million to net liabilities.  In 2010, changes in this exchange rate resulted in a foreign currency translation loss of $63 million, which primarily reflected a $180 million reduction to PP&E offset by a reduction of $117 million to net liabilities.  The impact of foreign currency translation is recorded in AOCI.

Related Party Transactions

PPL is not aware of any material ownership interests or operating responsibility by senior management of PPL, PPL Energy Supply, PPL Electric, LKE, LG&E or KU in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL.  See Note 16 to the Financial Statements for additional information on related party transactions.

Acquisitions, Development and Divestitures

PPL from time to time evaluates opportunities for potential acquisitions, divestitures and development projects.  Development projects are reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.

In April 2012, an indirect wholly owned subsidiary of PPL Energy Supply completed the Ironwood Acquisition.  In April 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of WPD Midlands.  In November 2010, PPL completed its acquisition of LKE.  See Note 10 to the Financial Statements for additional information.

See Notes 8, 9 and 10 to the Financial Statements for additional information on the more significant activities.

Environmental Matters

Extensive federal, state and local environmental laws and regulations are applicable to PPL's air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the cost of compliance or alleged non-compliance cannot be predicted with certainty but could be material.  In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed by the relevant agencies.  Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions.  Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost for their products or their demand for PPL's services.
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Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL's generation assets, electricity transmission and distribution systems, as well as impacts on customers.  In addition, changed weather patterns could potentially reduce annual rainfall in areas where PPL has hydro generating facilities or where river water is used to cool its fossil and nuclear powered generators.  PPL cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.

The below provides a discussion of the more significant environmental matters.

Coal Combustion Residuals (CCRs)
In June 2010, the EPA proposed two approaches to regulating CCRs (as either hazardous or non-hazardous) under existing solid waste regulations.  A final rulemaking is currently expected before the end of 2015.  However, the timing of the final regulations could be accelerated by certain litigation that could require the EPA to issue its regulations sooner.  Regulations could impact handling, disposal and/or beneficial use of CCRs.  The economic impact could be material if CCRs are regulated as hazardous waste, and significant if regulated as non-hazardous, in accordance with the proposed rule.

Effluent Limitation Guidelines
The EPA is to issue guidelines for technology-based limits in discharge permits for scrubber wastewater and is expected to require dry ash handling.  The EPA agreed, in recent settlement negotiations with environmentalists, to propose revisions to its effluent limitation guidelines (ELGs) by April 2013, with a final rule in late 2014.  Limits could be so stringent that plants may consider extensive new or modified wastewater treatment facilities and possibly zero liquid discharge operations, the cost of which could be significant.  Impacts should be better understood after the proposed rule is issued.

316(b) Cooling Water Intake Structure Rule
In April 2011, the EPA published a draft regulation under Section 316(b) of the Clean Water Act, which regulates cooling water intakes for power plants.  The draft rule has two provisions: one requires installation of Best Technology Available (BTA) to reduce mortality of aquatic organisms that are pulled into the plant cooling water system (entrainment), and the second imposes standards for reduction of mortality of aquatic organisms trapped on water intake screens (impingement).  A final rule is expected in June 2013.  The proposed regulation would apply to nearly all PPL-owned steam electric plants in Pennsylvania, Kentucky, and Montana, potentially even including those equipped with closed-cycle cooling systems.  PPL's compliance costs could be significant, especially if the final rule requires closed-cycle systems at plants that do not currently have them or conversions of once-through systems to closed-cycle.

GHG Regulations
In 2013, the EPA is expected to finalize limits on GHG emissions from new power plants and to begin working on a proposal for such emissions from existing power plants.  The EPA's proposal on GHG emissions from new power plants would effectively preclude construction of any coal-fired plants and could even be difficult for new gas-fired plants to meet.  With respect to existing power plants, the impact could be very significant, depending on the structure and stringency of the final rule.  PPL, along with others in the industry, filed comments on the EPA's proposal related to GHG emissions from new plants.  With respect to GHG limits for existing plants, PPL will advocate for reasonable, flexible requirements.

MATS
The EPA finalized MATS requiring fossil-fuel fired plants to reduce emissions of mercury and other hazardous air pollutants by April 16, 2015.  The rule is being challenged by industry groups and states.  The EPA has subsequently proposed changes to the rule with respect to new sources to address the concern that the rule effectively precludes new coal plants.  PPL is generally well-positioned to comply with MATS, primarily due to recent investments in environmental controls and approved Environmental Cost Recovery (ECR) plans to install additional controls at some of our Kentucky plants.  PPL is evaluating chemical additive systems for mercury control at Brunner Island, and modifications to existing controls at Colstrip for improved particulate matter reductions.  In September 2012, PPL announced its intention to place its Corette plant in long-term reserve status beginning in April 2015 due to expected market conditions and costs to comply with MATS.
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CSAPR and CAIR
In 2011, the EPA finalized its CSAPR regulating emissions of nitrous oxide and sulfur dioxide through new allowance trading programs which were to be implemented in two phases (2012 and 2014).  Like its predecessor, the CAIR, CSAPR targeted sources in the eastern United States.  In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit (the Court) stayed implementation of CSAPR, leaving CAIR in place.  Subsequently, in August 2012, the Court vacated and remanded CSAPR back to the EPA for further rulemaking, again leaving CAIR in place, pending further EPA action.  PPL plants in Pennsylvania and Kentucky will continue to comply with CAIR through optimization of existing controls, balanced with emission allowance purchases.  The Court's August decision leaves plants in CSAPR-affected states potentially exposed to more stringent emission reductions due to regional haze implementation (it was previously determined that CSAPR or CAIR participation satisfies regional haze requirements), and/or petitions to the EPA by downwind states under Section 126 of the Clean Air Act requesting the EPA to require plants that allegedly contribute to downwind non-attainment to take action to reduce emissions.

Regional Haze - Montana
The EPA signed its final Federal Implementation Plan (FIP) of the Regional Haze Rules for Montana in September 2012, with tighter emissions limits for Colstrip Units 1 & 2 based on the installation of new controls (no limits or additional controls were specified for Colstrip Units 3 & 4), and tighter emission limits for Corette (which are not based on additional controls).  The cost of the potential additional controls for Colstrip Units 1 & 2, if required, could be significant.  PPL expects to meet the tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" discussion above).

See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for further discussion of environmental matters.

Competition

See "Competition" under each of PPL's reportable segments in "Item 1. Business - Segment Information" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting PPL.

New Accounting Guidance

See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.

Application of Critical Accounting Policies

Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies.  The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain.  Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements).  Senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.

Price Risk Management

See "Price Risk Management" in Note 1 to the Financial Statements, as well as "Risk Management - Energy Marketing & Trading and Other" above.

Defined Benefits

Certain PPL subsidiaries sponsor various qualified funded and non-qualified unfunded defined benefit pension plans.  Certain PPL subsidiaries also sponsor both funded and unfunded other postretirement benefit plans.  These plans are applicable to the majority of the employees of PPL.  PPL and certain of its subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates.  Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.  See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
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PPL and its subsidiaries make certain assumptions regarding the valuation of benefit obligations and the performance of plan assets.  When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle.  Annual net periodic defined benefit costs are recorded in current earnings based on estimated results.  Any differences between actual and estimated results are recorded in OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates.  These amounts in AOCI or regulatory assets and liabilities are amortized to income over future periods.  The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans.  The primary assumptions are:

·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  These projected returns reduce the net benefit costs PPL records currently.

·Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

·Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.

In selecting a discount rate for its U.S. defined benefit plans, PPL starts with a cash flow analysis of the expected benefit payment stream for its plans.  The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds.  This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds.  Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.  At December 31, 2012, PPL decreased the discount rate for its U.S. pension plans from 5.06% to 4.22% and decreased the discount rate for its other postretirement benefit plans from 4.80% to 4.00%.

In selecting a discount rate for its U.K. defined benefit plans, PPL starts with a cash flow analysis of the expected benefit payment stream for its plans.  These plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate, which used an iBoxx British pounds sterling denominated corporate bond index as its base.  An individual bond matching approach is not used for U.K. pension plans because the universe of bonds in the U.K. is not deep enough to adequately support such an approach.  At December 31, 2012, the discount rate for the U.K. pension plans was decreased from 5.24% to 4.27% as a result of this assessment.

The expected long-term rates of return for PPL's U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class.  PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific asset allocation is also considered in developing a reasonable return assumption.

At December 31, 2012, PPL's expected return on plan assets decreased from 7.07% to 7.02% for its U.S. pension plans and increased from 5.93% to 5.97% for its other postretirement benefit plans.  The expected long-term rates of return for PPL's U.K. pension plans have been developed by PPL management with assistance from an independent actuary using a best-estimate of expected returns, volatilities and correlations for each asset class.  For the U.K. plans, PPL's expected return on plan assets decreased from 7.17% to 7.16% at December 31, 2012.

In selecting a rate of compensation increase, PPL considers past experience in light of movements in inflation rates.  At December 31, 2012, PPL's rate of compensation increase decreased from 4.02% to 3.98% for its U.S. pension plans and 4.00% to 3.97% for its other postretirement benefit plans.  For the U.K. plans, PPL's rate of compensation increase remained at 4.00% at December 31, 2012.
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In selecting health care cost trend rates, PPL considers past performance and forecasts of health care costs.  At December 31, 2012, PPL's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LG&E, KU and PPL Electric.  While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LG&E, KU and PPL Electric by a similar amount in the opposite direction.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.

At December 31, 2012, the defined benefit plans were recorded as follows.

Pension liabilities (2,084)
Other postretirement benefit liabilities (301)

The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL's primary defined benefit plans.

  Increase (Decrease)
     Impact on    Impact on
  Change in defined benefit Impact on regulatory
Actuarial assumption assumption liabilities OCI assets
             
Discount Rate  (0.25)% $ 473  $ (389) $ 84 
Rate of Compensation Increase  0.25%   66    (54)   12 
Health Care Cost Trend Rate (a)  1.00%   7    (1)   6 

(a)Only impacts other postretirement benefits.

In 2012, PPL recognized net periodic defined benefit costs charged to operating expensebelieve are indicative of $166 million.  This amount represents a $12 million increase from 2011, excluding $50 million of separation costs recorded in 2011.  The increase was primarily attributable to increased amortization of losses and a non-qualified plan settlement charge recorded in 2012.

The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL's primary defined benefit plans.

Actuarial assumption  Change in assumption  Impact on defined benefit costs
       
Discount Rate  (0.25)% $ 24 
Expected Return on Plan Assets  (0.25)%   26 
Rate of Compensation Increase  0.25%   10 
Health Care Cost Trend Rate (a)  1.00%   1 

(a)Only impacts other postretirement benefits.

Asset Impairment (Excluding Investments)

Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable.  For these long-lived assets classified as held and used, such events or changes in circumstances are:

·a significant decrease in the market price of an asset;
·a significant adverse change in the manner in which an asset is being used or in its physical condition;
·a significant adverse change in legal factors or in the business climate;
·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
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For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value.  Management must make significant judgments to estimate future cash flows, including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets.  Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome.  If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives.  For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets.  That assessment is not revised based on events that occur after the balance sheet date.  Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.

In September 2012, PPL Energy Supply announced its intention, beginning in April 2015, to place the Corette coal-fired plant in Montana in long-term reserve status, suspending the plant's operation, due to expected market conditions and the costs to comply with MATS requirements.  The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million.  An impairment analysis was performed for this asset group in the third and fourth quarters of 2012 and it was determined to not be impaired.  It is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.

For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell.  If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell.  A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.

For determining fair value, quoted market prices in active markets are the best evidence.  However, when market prices are unavailable, the Registrant considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained.  Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available.  Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.

Goodwill is tested for impairment at the reporting unit level.  PPL's reporting units have been determined to be at the operating segment level.  A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value.  Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.

Beginning in 2012, PPL may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test.  If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary.  However, the quantitative impairment test is required if PPL concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.

When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, PPL identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying amount, including goodwill, on the measurement date.  If the estimated fair value of a reporting unit exceeds its carrying amount, goodwill is not considered impaired.  If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.

The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination.  That is, the estimated fair value of a reporting unit is allocated to all of the assets and liabilities of that reporting unit as if the reporting unit had been acquired in a business combination and the estimated fair value of the reporting unit was the price paid to acquire the reporting unit.  The excess of the estimated fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill.  The implied fair value of the reporting unit's goodwill is then compared with the carrying amount of that goodwill.  If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess.  The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
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PPL elected to perform the two-step quantitative impairment test of goodwill for all of its reporting units in the fourth quarter of 2012 and no impairment was recognized.  Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of the reporting units.  For the U.K. Regulated reporting unit, management used only discounted cash flows to estimate the fair value of the reporting unit due to lack of industry comparable transactions.  Applying an appropriate weighting to both the discounted cash flow and market multiple valuations (where applicable) a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.

Loss Accruals

Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes.  For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated.  Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur."  The accrual of contingencies that might result in gains is not recorded unless recovery is assured.  Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.

The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient.  All three of these aspects require significant judgment by management.  Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.

No new significant loss accruals were recorded in 2012.  

Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual.  Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred.

When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable.  The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated.  The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:

·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable.

Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate.  This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.

See Note 6 and 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.  Note 6 to the Financial Statements includes a discussion of the Ofgem Review of Line Loss Calculation, including the $90 million reduction in the WPD liability.

Asset Retirement Obligations

PPL is required to recognize a liability for legal obligations associated with the retirement of long-lived assets.  The initial obligation is measured at its estimated fair value.  A conditional ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated.  An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset.  Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the statement of income, for changes in the obligation due to the passage of time.

In the case of LG&E and KU, since costs of removal are collected in rates, the depreciation and accretion expense related to an ARO are offset with a regulatory credit on the income statement, such that there is no earnings impact.  The regulatory asset created by the regulatory credit is relieved when the ARO has been settled.
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See Note 21 to the Financial Statements for further discussion of AROs.

In determining AROs, management must make significant judgments and estimates to calculate fair value.  Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred.  Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements.  Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO.  Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset.

At December 31, 2012, AROs totaling $552 million were recorded on the Balance Sheet, of which $16 million is included in "Other current liabilities."  Of the total amount, $316 million, or 57%, relates to the nuclear decommissioning ARO.  The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates.  A variance in any of these inputs could have a significant impact on the ARO liabilities.

The following table reflects the sensitivities related to the nuclear decommissioning ARO liability associated with a change in these assumptions as of December 31, 2012.  There is no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of changing the assumptions.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.

  Change in Impact on
  Assumption ARO Liability
       
Retirement Cost  10% $32
Discount Rate  (0.25)%  28
Inflation Rate  0.25%  32

Income Taxes

Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position.  Tax positions are evaluated following a two-step process.  The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained.  This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position.  The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion.  The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%.  Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date.  Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured.  The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.

At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $10 million or decrease by up to $90 million.  This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the creditability of foreign taxes, the timing and utilization of foreign tax credits and the related impact on alternative minimum tax and other credits, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
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The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment.  Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.  Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset.  Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies.  Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position.  Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances.  The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.  See Note 5 to the Financial Statements for income tax disclosures.

Regulatory Assets and Liabilities

PPL Electric, LG&E and KU, are subject to cost-based rate regulation.  As a result, the effects of regulatory actions are required to be reflected in the financial statements.  Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates.  Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.  In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation.  Based on this continual assessment, management believes the existing regulatory assets are probable of recovery.  This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future.  If future recovery of costs ceases to be probable, then asset write-offs would be required to be recognized in operating income.  Additionally, the regulatory agencies can provide flexibility in the manner and timing of depreciation of PP&E and amortization of regulatory assets.

At December 31, 2012, PPL had regulatory assets of $1.5 billion and regulatory liabilities of $1.1 billion.  All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.

See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.

WPD operates in an incentive-based regulatory structure under distribution licenses granted by Ofgem.  WPD's electricity distribution revenues are set every five years through price controls that are not directly based on cost recovery; therefore, WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities.

Other Information

PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules.  The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.

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PPL ENERGY SUPPLY, LLC AND SUBSIDIARIES

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

The information provided in this Item 7 should be read in conjunction with PPL Energy Supply's Consolidated Financial Statements and the accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

·  "Overview" provides a description of PPL Energy Supply and its business strategy, a summary of Net Income Attributable to PPL Energy Supply Member and a discussion of certain events related to PPL Energy Supply's results of operations and financial condition.

·  "Results of Operations" provides a summary of PPL Energy Supply's earnings and a description of key factors expected to impact future earnings.  This section ends with explanations of significant changes in principal items on PPL Energy Supply's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.

·  "Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL Energy Supply's liquidity position and credit profile.  This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.

·  "Financial Condition - Risk Management - Energy Marketing & Trading and Other" provides an explanation of PPL Energy Supply's risk management programs relating to market and credit risk.

·  "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL Energy Supply and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.

Overview

Introduction

PPL Energy Supply is an energy company with headquarters in Allentown, Pennsylvania.  Through its subsidiaries, PPL Energy Supply is primarily engaged in the generation and marketing of electricity in two key markets - the northeastern and northwestern U.S.

Business Strategy

PPL Energy Supply's overall strategy is to achieve disciplined optimization of energy supply margins while mitigating volatility in both cash flows and earnings.  More specifically, PPL Energy Supply's strategy is to optimize the value from its competitive generation and marketing portfolios.  PPL Energy Supply endeavors to do this by matching energy supply with load, or customer demand, under contracts of varying durations with creditworthy counterparties to capture profits while effectively managing exposure to energy and fuel price volatility, counterparty credit risk and operational risk.

To manage financing costs and access to credit markets, a key objective of PPL Energy Supply's business strategy is to maintain a strong credit profile and strong liquidity position.  In addition, PPL Energy Supply has financial and operational risk management programs that, among other things, are designed to monitor and manage its exposure to earnings and cash flow volatility related to changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of its generating units.

Financial and Operational Developments

Net Income Attributable to PPL Energy Supply Member

Net Income Attributable to PPL Energy Supply Member for 2012, 2011 and 2010 was $474 million, $768 million and $861 million.  Earnings in 2012 decreased 38% from 2011 and earnings in 2011 decreased 11% from 2010.

See "Results of Operations" below for further discussion and analysis of the consolidated results of operations.

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Economic and Market Conditions

Unregulated Gross Energy Margins associated with PPL Energy Supply's competitive generation and marketing business are impacted by changes in market prices and demand for electricity and natural gas, power plant availability, competition in the markets for retail customers, fuel costs and availability, fuel transportation costs and other costs.  Current depressed wholesale market prices for electricity and natural gas have resulted from general weak economic conditions and other factors, including the impact of expanded domestic shale gas development and production.  As a result of these factors, PPL Energy Supply has experienced a shift in the dispatching of its competitive generation from coal-fired to combined-cycle gas-fired generation as illustrated in the following table:

   Average Utilization Factors (a)
   2012   2009 - 2011
Pennsylvania coal plants  69%  87%
Montana coal plants  67%  89%
Combined-cycle gas plants  98%  72%

(a)All periods reflect the years ended December 31.

This reduction in coal-fired generation output had resulted in a surplus of coal inventory at certain of PPL Energy Supply's Pennsylvania coal plants.  To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million in 2012 to reduce its 2012 and 2013 contracted coal deliveries.  PPL Energy Supply will continue to manage its coal inventory to mitigate the financial impact and physical implications of an oversupply; however, no additional coal contract modifications are expected at this time.

In addition, current economic and commodity market conditions indicated a lower value of unhedged future energy margins (primarily in 2014 and forward years) compared to the energy margins in 2012.  As has been PPL Energy Supply's practice in periods of changing business conditions, PPL Energy Supply continues to review its future business and operational plans, including capital and operation and maintenance expenditures, as well as its hedging strategies, to help counter the financial effects of low commodity prices.

PPL Energy Supply's businesses are subject to extensive federal, state and local environmental laws, rules and regulations.  PPL Energy Supply's competitive generation assets are well positioned to meet these requirements.  See Note 15 to the Financial Statements for additional information on these requirements.  As a result of these requirements, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place its Corette plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with MATS.  The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million.  Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.

In light of these economic and market conditions, as well as current and projected environmental regulatory requirements, PPL Energy Supply considered whether certain of its other generating assets were impaired, and determined that no impairment charges were required at December 31, 2012.  PPL Energy Supply is unable to predict whether future environmental requirements or market conditions will result in impairment charges for other generating assets or other retirements.

PPL Energy Supply and its subsidiaries may also be impacted in future periods by the uncertainty in the worldwide financial and credit markets.  In addition, PPL Energy Supply may be impacted by reductions in the credit ratings of financial institutions and evolving regulations in the financial sector.  Collectively, these factors could reduce availability or restrict PPL Energy Supply and its subsidiaries' ability to maintain sufficient levels of liquidity, reduce capital market activities, change collateral posting requirements and increase the associated costs to PPL Energy Supply and its subsidiaries.

PPL Energy Supply cannot predict the future impact that these economic and market conditions and regulatory requirements may have on its financial condition or results of operations.

Susquehanna Turbine Blade Inspection

During 2012, PPL Energy Supply performed inspections of the Unit 1 and Unit 2 turbine blades at the PPL Susquehanna nuclear power plant to further address the issue of turbine blade cracking that was first identified in 2011.  The after-tax earnings impact of these 2012 inspections, including reduced energy-sales margins and repair expenses, was approximately $53 million.  The after-tax earnings impact of turbine blade related outages in 2011 was approximately $63 million.

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Ironwood Acquisition

In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility.  The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021.  The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM.  See Note 10 to the Financial Statements for additional information.

Bankruptcy of SMGT

In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Montana.  At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure.  This contract was accounted for as NPNS by PPL EnergyPlus.

The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices.  Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract.  In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February.  In March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT bankruptcy trustee and PPL EnergyPlus to terminate the SMGT Contract.  As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell the electricity previously contracted to SMGT under the SMGT Contract to other customers.

PPL EnergyPlus' receivable under the SMGT Contract totaled approximately $21 million at December 31, 2012, which has been fully reserved.

In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding.  The total claim is approximately $375 million, including the above receivable, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract.  No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.

PPL Energy Supply cannot predict any amounts that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.

Results of Operations

The following discussion provides a summary of PPL Energy Supply's earnings and a description of factors that are expected to impact future earnings.  This section ends with "Statement of Income Analysis," which includes explanations of significant year-to-year changes in Unregulated Gross Energy Margins by region and principal line items on PPL Energy Supply's Statements of Income.

Earnings
           
Net Income Attributable to PPL Energy Supply Member was:
           
   2012  2011  2010 
           
Net Income Attributable to PPL Energy Supply Member $ 474  $ 768  $ 861 

The changes in the components of Net Income Attributable to PPL Energy Supply Member between these periods were due to the following factors, which reflect reclassifications for items included in the Unregulated Gross Energy Margins and certain items that management considers special.  See additional detail of these special items in the tables below.

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  2012 vs. 2011 2011 vs. 2010
       
Unregulated Gross Energy Margins $ (197) $ (405)
Other operation and maintenance   (53)   (65)
Depreciation   (41)   (8)
Taxes, other than income   6    (9)
Other Income (Expense) - net   (5)   
Interest Expense   16    4 
Other   (1)   
Income Taxes   102    146 
Discontinued operations - Domestic, after-tax - excluding certain revenues and expenses included in margins   3    16 
Discontinued operations - International, after-tax      (261)
Special items, after-tax   (124)   489 
Total $ (294) $ (93)

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Unregulated Gross Energy Margins.

·Higher other operation and maintenance in 2012 compared with 2011 due to higher costs at PPL Susquehanna of $27 million including refueling outage costs, payroll-related costs and project costs, $18 million due to the Ironwood Acquisition, $13 million due to outages at eastern fossil and hydroelectric units and $10 million of charges from support groups partially offset by $34 million of trademark royalties with an affiliate in 2011 for which the agreement was terminated December 31, 2011.

Higher other operation and maintenance in 2011 compared with 2010, primarily due to higher costs at PPL Susquehanna of $30 million largely due to unplanned outages, the refueling outage and payroll-related costs, higher costs at eastern fossil and hydroelectric units of $20 million, largely due to outages, and higher costs at western fossil and hydroelectric units of $15 million, largely resulting from insurance recoveries received in 2010.

·Higher depreciation in 2012 compared with 2011 primarily due to a $16 million impact from PP&E additions and $17 million due to the Ironwood Acquisition.

·Lower interest expense in 2012 compared with 2011 of $14 million due to the impact of redeeming debt not replaced and redeeming debt replaced at a lower interest rate, $10 million due to lower interest on short-term borrowings and $7 million due to 2011 including the acceleration of deferred financing fees related to the July 2011 redemption, partially offset by a $12 million increase related to the debt assumed as a result of the Ironwood Acquisition.

·Lower income taxes in 2012 compared with 2011 due to lower 2012 pre-tax income, which reduced income taxes by $110 million and $20 million related to lower adjustments to valuation allowances on Pennsylvania net operating losses, partially offset by $26 million related to the impact of prior period tax return adjustments.

Lower income taxes in 2011 compared with 2010, due to lower 2011 pre-tax income, which reduced income taxes by $196 million and a $26 million reduction in deferred tax liabilities related to an updated blended state tax rate as a result of a change in state apportionment.  These decreases were partially offset by $74 million related to adjustments to valuation allowances on Pennsylvania net operating losses, $13 million in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction tax benefit resulting from revised bonus depreciation estimates.

·Discontinued operations - International, represents the results of PPL Global which was distributed to PPL Energy Supply's parent, PPL Energy Funding in January 2011.  See Note 9 to the Financial Statements for additional information.

The following after-tax gains (losses), which management considers special items, also impacted the results.

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   Income Statement         
   Line Item 2012  2011  2010 
           
Adjusted energy-related economic activity, net, net of tax of ($26), ($52), $85(a) $ 38  $ 72  $ (121)
Sales of assets:          
 Maine hydroelectric generation business, net of tax of $0, $0, ($9) (b)Disc. Operations         15 
 Sundance indemnification, net of tax of $0, $0, $0Other Income-net         1 
Impairments:          
 Emission allowances, net of tax of $0, $1, $6 (c)Other O&M      (1)   (10)
 Renewable energy credits, net of tax of $0, $2, $0Other O&M      (3)   
 Adjustments - nuclear decommissioning trust investments, net of tax of ($2), $0, $0Other Income-net   2       
 Other asset impairments, net of tax of $0, $0, $0Other O&M   (1)      
LKE acquisition-related adjustments:          
 Monetization of certain full-requirement sales contracts, net of tax of $0, $0, $89(d)         (125)
 Sale of certain non-core generation facilities, net of tax of $0, $0, $37 (e)Disc. Operations      (2)   (64)
 Reduction of credit facility, net of tax of $0, $0, $4 (f)Interest Expense         (6)
Other:          
 Montana hydroelectric litigation, net of tax of $0, ($30), $22(g)      45    (34)
 Litigation settlement - spent nuclear fuel storage, net of tax of $0, ($24), $0 (h)Fuel      33    
 Health care reform - tax impact (i)Income Taxes         (5)
 Montana basin seepage litigation, net of tax of $0, $0, ($1)Other O&M         2 
 Counterparty bankruptcy, net of tax of $5, $5, $0 (j)Other O&M   (6)   (6)   
 Wholesale supply cost reimbursement, net of tax of $0, ($3), $0(k)   1    4    
 Ash basin leak remediation adjustment, net of tax of ($1), $0, $0Other O&M   1       
 Coal contract modification payments, net of tax of $12, $0, $0 (l)Fuel   (17)      
Total  $ 18  $ 142  $ (347)
(a)See "Reconciliation of Economic Activity" below.
(b)Gains recorded on completion of the sale of the Maine hydroelectric generation business.  See Note 9 to the Financial Statements for additional information.
(c)Primarily represents impairment charges of sulfur dioxide emission allowances.
(d)In July 2010, in order to raise additional cash for the LKE acquisition, certain full-requirement sales contracts were monetized that resulted in cash proceeds of $249 million.  See "Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information.  $343 million of pre-tax gains were recorded to "Wholesale energy marketing" and $557 million of pre-tax losses were recorded to "Energy purchases" on the Statement of Income.
(e)Consists primarily of the initial impairment charge recorded when the business was classified as held for sale.  See Note 9 to the Financial Statements for additional information.
(f)In October 2010, PPL Energy Supply made borrowings under its Syndicated Credit Facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE.  Subsequent to the repayment of such borrowing, the capacity was reduced, and as a result, PPL Energy Supply wrote off deferred fees in 2010.
(g)In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds.  In 2010, PPL Montana recorded a pre-tax charge of $56 million, representing estimated rental compensation for years prior to 2010, including interest.  Of this total charge $47 million, pre-tax, was recorded to "Other operation and maintenance" and $9 million, pre-tax, was recorded to "Interest Expense" on the Statement of Income.  In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter.  In June 2011, the U.S. Supreme Court granted PPL Montana's petition.  In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion.  Prior to the U.S. Supreme Court decision, $4 million, pre-tax, of interest expense on the rental compensation covered by the court decision was accrued in 2011.  As a result of the U.S. Supreme Court decision, PPL Montana reversed its total pre-tax loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $79 million pre-tax is considered a special item because it represented $65 million of rent for periods prior to 2011 and $14 million of interest accrued on the portion covered by the prior court decision.  These amounts were credited to "Other operation and maintenance" and "Interest Expense" on the Statement of Income.  See Note 15 to the Financial Statements for additional information.
(h)In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant.  PPL Susquehanna recorded credits to fuel expense to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant.  This special item represents amounts recorded in 2011 to cover the costs incurred from 1998 through December 2010.
(i)Represents income tax expense recorded as a result of the provisions within Health Care Reform which eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.
(j)In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code.  In 2012, PPL EnergyPlus recorded an additional allowance for unpaid amounts under the long-term power contract.  In March 2012, the U.S. Bankruptcy Court for the District of Montana approved the request to terminate the contract, effective April 1, 2012.
(k)In January 2012, PPL received $7 million pre-tax, related to electricity delivered to a wholesale customer in 2008 and 2009, recorded in "Wholesale energy marketing-Realized."  The additional revenue results from several transmission projects approved at PJM for recovery that were not initially anticipated at the time of the electricity auctions and therefore were not included in the auction pricing.  A FERC order was issued in 2011 approving the disbursement of these supply costs by the wholesale customer to the suppliers, therefore, PPL Energy Supply accrued its share of this additional revenue in 2011.
(l)As a result of lower electricity and natural gas prices, coal-fired generation output decreased during 2012.  Contract modification payments were incurred to reduce 2012 and 2013 contracted coal deliveries.
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Reconciliation of Economic Activity

The following table reconciles unrealized pre-tax gains (losses) from the table within "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements to the special item identified as "Adjusted energy-related economic activity, net."

    2012  2011  2010 
Operating Revenues         
  Unregulated retail electric and gas $ (17) $ 31  $ 1 
  Wholesale energy marketing   (311)   1,407    (805)
Operating Expenses         
  Fuel   (14)   6    29 
  Energy Purchases   442    (1,123)   286 
Energy-related economic activity (a)   100    321    (489)
Option premiums (b)   (1)   19    32 
Adjusted energy-related economic activity   99    340    (457)
Less:  Unrealized economic activity associated with the monetization of certain         
 full-requirement sales contracts in 2010 (c)         (251)
Less:  Economic activity realized, associated with the monetization of certain         
 full-requirement sales contracts in 2010   35    216    
Adjusted energy-related economic activity, net, pre-tax $ 64  $ 124  $ (206)
            
Adjusted energy-related economic activity, net, after-tax $ 38  $ 72  $ (121)

(a)See Note 19 to the Financial Statements for additional information.
(b)Adjustment for the net deferral and amortization of option premiums over the delivery period of the item that was hedged or upon realization.  Option premiums are recorded in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statements of Income.
(c)See "Components of Monetization of Certain Full-Requirement Sales Contracts" below.

Components of Monetization of Certain Full-Requirement Sales Contracts

The following table provides the components of the "Monetization of Certain Full-Requirement Sales Contracts" special item.

2010 
Full-requirement sales contracts monetized (a)$ (68)
Economic activity related to the full-requirement sales contracts monetized (146)
Monetization of certain full-requirement sales contracts, pre-tax (b)$ (214)
Monetization of certain full-requirement sales contracts, after-tax$ (125)

(a)See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information.
(b)Includes unrealized losses of $251 million, which are reflected in "Wholesale energy marketing - Unrealized economic activity" and "Energy purchases - Unrealized economic activity" on the Statement of Income.  Also includes net realized gains of $37 million, which are reflected in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statement of Income.

2013 Outlook

Excluding special items, PPL Energy Supply projects lower earnings in 2013 compared with 2012, primarily driven by lower energy prices, higher fuel costs, higher operation and maintenance, higher depreciation and higher financing costs, which are partially offset by higher capacity prices and higher nuclear generation output despite scheduled outages for both Susquehanna units to implement a long-term solution to turbine blade issues.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Note 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
96
Statement of Income Analysis --

Unregulated Gross Energy Margins

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Unregulated Gross Energy Margins."  "Unregulated Gross Energy Margins" is a single financial performance measure of PPL Energy Supply's competitive energy non-trading and trading activities.  In calculating this measure, PPL Energy Supply's energy revenues, which include operating revenues associated with certain PPL Energy Supply businesses that are classified as discontinued operations, are offset by the cost of fuel, energy purchases, certain other operation and maintenance expenses, primarily ancillary charges, gross receipts tax, which is recorded in "Taxes, other than income," and operating expenses associated with certain PPL Energy Supply businesses that are classified as discontinued operations.  This performance measure is relevant to PPL Energy Supply due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Unregulated Gross Energy Margins."  This volatility stems from a number of factors, including the required netting of certain transactions with ISOs and significant fluctuations in unrealized gains and losses.  Such factors could result in gains or losses being recorded in either "Wholesale energy marketing" or "Energy purchases" on the Statements of Income.  This performance measure includes PLR revenues from energy sales to PPL Electric by PPL EnergyPlus, which are recorded in "Wholesale energy marketing to affiliate" revenue.  PPL Energy Supply excludes from "Unregulated Gross Energy Margins" adjusted energy-related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of PPL Energy Supply's competitive generation assets, full-requirement sales contracts and retail activities.  This economic value is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged.  Also included in adjusted energy-related economic activity is the ineffective portion of qualifying cash flow hedges, the monetization of certain full-requirement sales contracts and premium amortization associated with options.  This economic activity is deferred, with the exception of the full-requirement sales contracts that were monetized, and included in "Unregulated Gross Energy Margins" over the delivery period that was hedged or upon realization.  This measure is not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance.  Other companies may use different measures to analyze and to report on the results of their operations.  PPL Energy Supply believes that "Unregulated Gross Energy Margins" provides another criterion to make investment decisions.  This performance measure is used, in conjunction with other information, internally by senior management to manage PPL Energy Supply's operations, analyze actual results compared with budget and measure certain corporate financial goals used in determining variable compensation.

Reconciliation of Non-GAAP Financial Measures

The following tables reconcile "Operating Income" to "Unregulated Gross Energy Margins" as defined by PPL Energy Supply for the period ended December 31.

      2012  2011 
      Unregulated       Unregulated      
      Gross Energy    Operating Gross Energy     Operating
      Margins Other (a) Income (b) Margins Other (a) Income (b)
                   
Operating Revenues                    
 Wholesale energy marketing                    
    Realized $ 4,412  $ 21 (c) $ 4,433  $ 3,745  $ 62 (c) $ 3,807 
    Unrealized economic activity      (311)(d)   (311)      1,407 (d)   1,407 
 Wholesale energy marketing                    
  to affiliate   78        78    26        26 
 Unregulated retail electric and gas   865    (17)(d)   848    696    31 (d)   727 
 Net energy trading margins   4        4    (2)       (2)
 Energy-related businesses      448     448       464     464 
   Total Operating Revenues   5,359    141     5,500    4,465    1,964     6,429 

97
      2012  2011 
      Unregulated       Unregulated      
      Gross Energy    Operating Gross Energy     Operating
      Margins Other (a) Income (b) Margins Other (a) Income (b)
Operating Expenses                    
 Fuel   931    34 (e)   965    1,151    (71)(e)   1,080 
 Energy purchases                    
    Realized   2,204    56 (c)   2,260    912    248 (c)   1,160 
    Unrealized economic activity      (442)(d)   (442)      1,123 (d)   1,123 
 Energy purchases from affiliate   3        3    3        3 
 Other operation and maintenance   19    1,022     1,041    16    913     929 
 Depreciation      285     285       244     244 
 Taxes, other than income   34    35     69    30    41     71 
 Energy-related businesses      432     432       458     458 
   Total Operating Expenses   3,191    1,422     4,613    2,112    2,956     5,068 
 Discontinued Operations             12    (12)(f)   
Total $ 2,168  $ (1,281)  $ 887  $ 2,365  $ (1,004)  $ 1,361 
      2010  
      Unregulated       
      Gross Energy    Operating 
      Margins Other (a) Income (b) 
Operating Revenues           
 Wholesale energy marketing           
    Realized $ 4,511  $ 321 (c) $ 4,832  
    Unrealized economic activity      (805)(d)   (805) 
 Wholesale energy marketing           
  to affiliate   320        320  
 Unregulated retail electric and gas   414    1 (d)   415  
 Net energy trading margins   2        2  
 Energy-related businesses      364     364  
   Total Operating Revenues   5,247    (119)    5,128  
                
Operating Expenses           
 Fuel   1,132    (36)(e)   1,096  
 Energy purchases           
    Realized   1,389    247 (c)   1,636  
    Unrealized economic activity      (286)(d)   (286) 
 Energy purchases from affiliate   3        3  
 Other operation and maintenance   23    956     979  
 Depreciation      236     236  
 Taxes, other than income   14    32     46  
 Energy-related businesses      357     357  
   Total Operating Expenses   2,561    1,506     4,067  
 Discontinued Operations   84    (84)(f)    
Total $ 2,770  $ (1,709)  $ 1,061  
(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.
(c)Represents energy-related economic activity as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.  For 2012, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax loss of $35 million related to the monetization of certain full-requirement sales contracts.  2011 includes a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $19 million related to the amortization of option premiums.  2010 includes a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $32 million related to the amortization of option premiums.
(d)Represents energy-related economic activity, which is subject to fluctuations in value due to market price volatility, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.
(e)Includes economic activity related to fuel as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements.  2012 includes a net pre-tax loss of $29 million related to coal contract modification payments.  2011 includes pre-tax credits of $57 million for the spent nuclear fuel litigation settlement.
(f)Represents the net of certain revenues and expenses associated with certain businesses that are classified as discontinued operations.  These revenues and expenses are not reflected in "Operating Income" on the Statements of Income.

Changes in Non-GAAP Financial Measures

Unregulated Gross Energy Margins are generated through PPL Energy Supply's competitive non-trading and trading activities.  PPL Energy Supply's non-trading energy business is managed on a geographic basis that is aligned with its generation fleet.  The following table shows PPL Energy Supply's non-GAAP financial measure, Unregulated Gross Energy Margins, for the periods ended December 31, as well as the change between periods.  The factors that gave rise to the changes are described below the table.
98
   2012  2011  Change 2011  2010  Change
                    
Non-trading                  
 Eastern U.S. $ 1,865  $ 2,018  $ (153) $ 2,018  $ 2,429  $ (411)
 Western U.S.   299    349    (50)   349    339    10 
Net energy trading   4    (2)   6    (2)   2    (4)
Total $ 2,168  $ 2,365  $ (197) $ 2,365  $ 2,770  $ (405)

Unregulated Gross Energy Margins      
       
Eastern U.S.      
       
The changes in Eastern U.S. non-trading margins were:
       
  2012 vs. 2011 2011 vs. 2010
       
Baseload energy prices $ (121) $ (109)
Baseload capacity prices   (37)   (90)
Intermediate and peaking capacity prices   (17)   (58)
Full-requirement sales contracts (a)   (15)   70 
Impact of non-core generation facilities sold in the first quarter of 2011   (12)   (48)
Higher nuclear fuel prices   (12)   (10)
Net economic availability of coal and hydroelectric units (b)   (10)   (72)
Higher coal prices   (2)   (40)
Nuclear generation volume (c)      (29)
Intermediate and peaking Spark Spreads   11    24 
Retail electric   15    (7)
Ironwood Acquisition, which eliminated tolling expense (d)   41    
Monetization of certain deals that rebalanced the business and portfolio      (41)
Other   6    (1)
  $ (153) $ (411)

(a)Higher margins in 2011 compared with 2010 were driven by the monetization of loss contracts in 2010 and lower customer migration to alternative suppliers in 2011.
(b)Volumes were lower in 2011 compared with 2010 as a result of unplanned outages and the sale of our interest in Safe Harbor Water Power Corporation.
(c)Volumes were flat in 2012 compared to 2011 due to an uprate in the third quarter of 2011 offset by higher plant outage costs in 2012.  Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011.
(d)See Note 10 to the Financial Statements for additional information.

Western U.S.

Non-trading margins were lower in 2012 compared with 2011 due to $34 million of lower wholesale volumes, including $31 million related to the bankruptcy of SMGT, $9 million of higher average fuel prices and $9 million of lower wholesale prices.

Non-trading margins were higher in 2011 compared with 2010 due to higher net wholesale prices of $58 million, partially offset by lower wholesale volumes of $45 million, primarily due to economic reductions in the coal unit output.

Energy-Related Businesses

The $10 million increase inNet contributions to the East segment's operating income (loss) from energy-related businesses decreased by $4 million in 20122015 compared with 2011 primarily relates2014. Net contributions to the East segment's operating income (loss) increased by $13 million in 2014 compared with 2013. During 2014, Talen Energy recorded a $17 million increase to "Energy-related businesses" revenues on the 2014 Statements of Income related to prior periods and the timing of revenue recognition for a mechanical services businesses,contracting and engineering subsidiary. See Note 1 to the Financial Statements for additional information. Excluding the impact of the 2014 adjustment, the change in 2015 compared with 2014 was an increase of $13 million due to improvedhigher margins on existing construction projects at the mechanical contracting and energy service projectsengineering subsidiaries. The change in 2012 and a decrease in affiliate trademark expenses.2014 compared with 2013 was primarily due to the $17 million revenue adjustment.


Other
38

Operation and Maintenance

The increase (decrease) in other operation and maintenance was due to:

 2015 vs. 2014 2014 vs. 2013
East segment:   
RJS - Raven and Sapphire (a)$104
 $—
MACH Gen - Athens and Millennium (a)7
 —
Fossil and Hydro (b)(51) (9)
Nuclear (c)(21) 33
Talen Energy Marketing (d)(25) 4
Energy Services (e)(17) 4
West segment:   
RJS - Jade (a)22
 —
MACH Gen - Harquahala (a)3
 —
      Talen Montana (f)23
 (20)
Other:   
Accelerated stock-based compensation (g)25
 —
TSA costs29
 —
Restructuring costs (h)12
 —
Transaction costs (i)20
 —
Separation benefits (j)(17) 17
Separation costs (k)(14) 16
Other (l)(55) 1
Total$45

$46
99
   2012 vs. 2011 2011 vs. 2010
        
Montana hydroelectric litigation (a) $ 75  $ (121)
PPL Susquehanna nuclear plant costs (b)   27    30 
Uncollectible accounts (c)   (5)   15 
Costs at Western fossil and hydroelectric plants (d)   (1)   15 
Costs at Eastern fossil and hydroelectric plants (e)   13    20 
Impacts from emission allowances (f)      (15)
Ironwood Acquisition (g)   18    
Trademark royalties (h)   (34)   
Pension expense   11    1 
Other   8    5 
Total $ 112  $ (50)

(a)In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds.  As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million, representing estimated rental compensation for the first quarter of 2010 and prior years, including interest.  The portion of the total charge recorded to "Other operation and maintenance" on the Statement of Income totaled $49 million.  In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter.  In June 2011, the U.S. Supreme Court granted PPL Montana's petition.  In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion.  As a result, in 2011 PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $75 million was credited to "Other operation and maintenance" on the Statement of Income.
(b)2012 compared with 2011 was higher primarily due to $11 million of higher payroll-related costs, $7 million of higher project costs and $7 million of higher costs from the refueling outage.  2011 compared with 2010 was higher primarily due to $11 million of higher payroll-related costs, $10 million of higher outage costs and $8 million of higher costs from the refueling outage.
(c)2011 compared with 2010 was higher primarily due to SMGT filing for protection under Chapter 11 of the U.S. Bankruptcy Code, $11 million of damages billed to SMGT were fully reserved.
(d)2011 compared with 2010 was higher primarily due to $11 million of lower insurance proceeds.
(e)2012 compared with 2011 was higher primarily due to net plant outage costs of $13 million.  2011 compared with 2010 was higher primarily due to plant outage costs of $13 million.
(f)2011 compared with 2010 was lower due to lower impairment charges of sulfur dioxide emission allowances.
(g)(a)There are no comparable amounts in the 20112014 or 2013 periods as the Ironwood Acquisition occurredRJS was acquired in April 2012.June 2015 and MACH Gen was acquired in November 2015.
(h)In 2011
(b)The decrease for 2015 compared with 2014 and 2010, PPLthe decrease for 2014 compared with 2013 was primarily due to lower coal plant outage costs.
(c)The decrease for 2015 compared with 2014 was primarily due to $11 million of lower outage costs and $13 million of lower contractor costs supporting operations. The increase in 2014 compared with 2013 was primarily due to higher contractor costs supporting operations.
(d)The decrease for 2015 compared with 2014 was primarily due to lower payroll related costs attributable to restructuring activities.
(e)The decrease for 2015 compared with 2014 was primarily due to the gain on the sale of Talen Renewable Energy Supplyin November 2015.
(f)The increase for 2015 compared with 2014 was charged trademark royalties by an affiliate.primarily due to $8 million of higher coal plant outage costs and $7 million of costs associated with the retirement of the Corette plant in 2015. The agreementdecrease in 2014 compared with 2013 was primarily due to the elimination of $20 million of rent expense associated with the Colstrip lease that was terminated in December 2011.2013.
(g)Related to the spinoff transaction. See Note 1 to the Financial Statements for additional information.
(h)The increase for 2015 compared with 2014 was due to costs recorded in 2015 related to the spinoff transaction, including expenses for the FERC-required mitigation plan and legal and professional fees.
(i)The increase for 2015 compared with 2014 was due to costs recorded in 2015 related to the RJS, MACH Gen and mitigation asset sale transactions.
(j)The decrease for 2015 compared with 2014 and the increase in 2014 compared with 2013 was due to bargaining unit one-time voluntary retirement benefits recorded in 2014 as a result of the ratification of the IBEW Local 1600 three-year labor agreement in June 2014.
(k)The decrease for 2015 compared with 2014 and the increase in 2014 compared with 2013 was primarily due to costs incurred in 2014 related to restructuring in anticipation of the spinoff, which included cash severance compensation, lump sum COBRA reimbursement payments and outplacement services.
(l)The decrease for 2015 compared with 2014 was primarily due to lower corporate expenses.

Loss on Lease Termination

A $697 million charge was recorded in 2013 for the termination of the Colstrip operating lease to facilitate the sale of the Montana hydroelectric generating facilities. See Note 6 to the Financial Statements for additional information.

Impairments

Impairments in 2015 primarily include a $465 million goodwill impairment, a $175 million impairment of the Sapphire plants and a $14 million impairment of the C.P. Crane plant (all included in the East segment). 2013 includes a $65 million impairment of the Corette plant (included in the West segment). These impairments exclude those recorded to "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2014 Statement of Income. See Note 16 to the Financial Statements for additional information.


39

Depreciation

Depreciation increased by $41$59 million in 20122015 compared with 2011,2014, primarily due to $16increases in the East and West segments of $31 million attributableand $25 million, primarily related to the acquisitions of RJS Power and MACH Gen. There are no comparable amounts in 2014 and 2013 for RJS or MACH Gen as their acquisition occurred in 2015.

Depreciation decreased by $2 million in 2014 compared with 2013, primarily due to an $8 million increase in the East segment and a $10 million decrease in the West segment. The increase in the East segment was partially due to $13 million from PP&E additions and $17 million attributablein part due to the Ironwood Acquisitioncompleted Holtwood expansion project in April 2012.  Depreciation increased by $8 million2013. The decrease in 2011 compared with 2010,the West segment was primarily due to PP&E additions.decreases from the impairment of the Corette plant and the write off of leasehold improvement assets in conjunction with the termination of the operating lease at the Colstrip facility, both of which occurred in 2013. See Note 14 to the Financial Statements for additional information on the Corette impairment and Note 6 to the Financial Statements for information on the Colstrip operating lease termination.

Taxes, Other Than Income

Taxes, other than income decreasedincreased by $2$8 million in 2012for 2015 compared with 2011,2014. This increase was primarily due to a$11 million related to RJS, $7 million decrease in state capital stock tax offset by aimpacting the East segment and $4 million increase in state gross receipts tax.

impacting the West segment. Taxes other than income increased by $25$4 million in 20112014 compared with 2010, primarily due to $16 million of higher Pennsylvania gross receipts tax expense2013, within the East segment. There are no comparable amounts in 2014 and 2013 for RJS as a result of an increasethe acquisition occurred in retail electricity sales by PPL EnergyPlus.  This tax is included in "Unregulated Gross Energy Margins."  The increase also includes $8 million of higher Pennsylvania capital stock tax due in part to the expiration of the Keystone Opportunity Zone credit in 2010 and an agreed to change in a capital stock tax filing position with the state.2015.

Other Income (Expense) - net

See Note 17 to the Financial Statements for details.

Interest Income from Affiliates

InterestOther income from affiliates(expense) - net decreased by $6$148 million in 20122015 compared with 2011,2014 and decreased by $2 million in 2014 compared with 2013. The decrease in 2015 compared with 2014 was primarily due to lower average loan balancesthe recording of a $134 million charge for a termination payment to a remarketing dealer related to an October 2015 debt extinguishment and a $9 million decrease in 2015 in net earnings on the NDT funds. See Note 5 for additional information on the debt extinguishment. The decrease in 2014 compared with PPL Energy Funding.2013 resulted from 2013 including a gain of $8 million related to adjustments to liabilities for a former mining subsidiary partially offset by a $5 million increase in 2014 in net earnings on the NDT funds.

Interest Expense

The increase (decrease) in interest expense was due to:

100
   2012 vs. 2011 2011 vs. 2010
        
Long-term debt interest expense (a) $ (11)   
Short-term debt interest expense (b)   (10) $7 
Ironwood Acquisition (Note 10)  12    
Capitalized interest      (16)
Net amortization of debt discounts, premiums and issuance costs (c)   (9)   (3)
Montana hydroelectric litigation (d)   10    (20)
Other   2    (2)
Total $ (6) $ (34)
 2015 vs. 2014 2014 vs. 2013
Long-term debt interest expense (a)$56
 $(50)
MACH Gen (b)6
 —
Short-term debt interest expense11
 7
Capitalized interest (c)3
 14
Net amortization of debt discounts, premiums and issuance costs (d)11
 (4)
Other—
 (2)
Total$87
 $(35)

(a)The increase in 2015 compared with 2014 was due to a debt issuance in May 2015 and the assumption of an RJS Power subsidiary's debt in June 2015 in connection with the RJS Power acquisition, partially offset by a debt maturity in August 2014. The increase in expense from the RJS Power related debt was $35 million. See Note 6 to the Financial Statements for information on the acquisition. The decrease in 2014 compared with 2013 was primarily due to the redemptionrepayment of $250 million of 7.0% Senior Notes due 2046debt in July 2011 along with the repayment of $500 million of 6.4% Senior Notes due 2011 and subsequent issuance of $500 million of 4.6% Senior Notes due 2021, bothDecember 2013.
(b)Represents interest on long-term debt. There are no comparable amounts in the fourth quarter of 2011.2014 or 2013 periods as MACH Gen was acquired in November 2015. See Note 6 to the Financial Statements for additional information on the acquisition.
(b)2012
(c)The increase in 2014 compared with 20112013 was lower primarily due to lower interest rates on 2012 short-term borrowings coupled with lower fees on credit facilities.  2011the Holtwood hydroelectric expansion project placed in service in November 2013.
(d)The increase in 2015 compared with 20102014 was higher primarily due to increased borrowings in 2011 and an increase in commitment fees on credit facilities.
(c)The periods include the impact of accelerating the amortization of deferred financing fees of $7 million in 2011, due to the July 2011 redemption, as noted above,write-off of its 7.00% Senior Notes due 2046.  2011 comparedfees associated with 2010Talen Energy Supply's $3 billion syndicated credit facility that was slightly offset by the impact of accelerating the amortization of deferred financing fees of $10 millionterminated in 2010, due to the September 2010 expiration and subsequent replacement of its $3.2 billion 5-year Syndicated Credit Facility.
(d)In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds.  In August 2010, PPL Montana filed a petition for a writ of certiorariconnection with the U.S. Supreme Court requesting the Court's review of this matter.  In 2011 and 2010, PPL Montana recorded $4 million and $10 million of interest expense on the rental compensation covered by the court decision.  In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion.  As a result, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $14 million was credited to "Interest Expense" on the Statement of Income.spinoff.


40

Income Taxes

The increase (decrease) in income taxes was due to:

  2012 vs. 2011 2011 vs. 2010
       
Higher (lower) pre-tax book income $ (191) $ 134 
State valuation allowance adjustments (a)   (20)   74 
State deferred tax rate change (b)   7    (26)
Domestic manufacturing deduction (c) (d)      11 
Federal and state tax reserve adjustments   (4)   13 
Federal and state tax return adjustments (d)   26    (16)
Health Care Reform (e)      (5)
Other      (1)
  $ (182) $ 184 
 2015 vs. 2014 2014 vs. 2013
Change in pre-tax income at current tax rates (a)$(36) $298
RJS (b)(49) —
MACH Gen (b)(5) —
Federal and state uncertain tax benefits recognized (c)(12) —
State deferred tax rate change (d)(16) (16)
Goodwill impairment (e)(21) —
Federal income tax credits (f)(9) 8
Federal and state tax return adjustments(7) (6)
Other12
 (9)
Total$(143) $275

(a)During 2011,Excludes income taxes related to RJS and MACH Gen as there are no comparable amounts in 2014 or 2013 as their acquisition occurred in 2015. Also excludes the Pennsylvania Departmentimpact of Revenue issued interpretive guidancethe goodwill impairment recorded in 2015 because the effective tax rate on the treatmentimpairment does not bear a customary relationship to the recognized loss as a result of bonus depreciation for Pennsylvania income tax purposes.  The guidance allows 100% bonus for qualifying assetsa significant portion of the impairment being related to non-deductible goodwill.
(b)There are no comparable amounts in the same year bonus depreciation is allowed2014 or 2013 periods as RJS was acquired in June 2015 and MACH Gen was acquired in November 2015.
(c)In 2015, open audits for federal incomethe tax purposes.  Due toyears 2008 - 2011 were settled by PPL with the decreaseIRS resulting in projected taxable incomea tax benefit of $12 million for Talen Energy's portion of the settlement of previously unrecognized tax benefits.
(d)During 2015, 2014 and 2013, Talen Energy recorded adjustments related to bonus depreciation and a decrease in projected future taxable income, PPL Energy Supply recorded $22 million inits December 31 state deferred income tax expense related to deferred tax valuation allowances during 2011.

Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010.  Based on the projected revenue increase related to the expiration of the generation rate caps, PPL Energy Supply recorded a $52 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances over the remaining carryforward period of the net operating losses during 2010.
(b)Changesliabilities as a result of annual changes in state apportionment resulted in reductions toand the impact on the future estimated state income tax rate at December 31, 2012 and 2011.  PPL Energy Supply recorded a $19 million deferred tax benefit in 2012 and a $26 million deferred tax benefit in 2011 related to its state deferred tax liabilities.rate.
(c)In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property.  The increased tax depreciation deduction eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 2011.
(d)(e)During 2011, PPL recorded $22 million in federalFederal and state tax benefits relatedimpacts attributable to the filingdeductible portion of goodwill that was impaired during the 2010 federal and state income tax returns.  Of that amount, $7 million in tax benefits related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts.
(e)Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibilitythird quarter of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.  As a result, PPL Energy Supply recorded deferred income tax expense during 2010.

2015. See Note 516 to the Financial Statements for additional information on income taxes.the goodwill impairment.
(f)During 2015, Talen Energy recorded a benefit primarily related to the recognition of previously unamortized tax credits as a result of the sale of Talen Renewable Energy in November 2015. During 2013, Talen Energy recorded a deferred tax benefit related to investment tax credits on progress expenditures for the Holtwood hydroelectric plant expansion. See Note 6 to the Financial Statements for additional information.
  
See Note 4 to the Financial Statements for additional information.

101
Income (Loss) from Discontinued Operations (net of income taxes)

Income (Loss) from Discontinued Operations (net of income taxes) decreased by $240 millionfor 2014 and 2013 includes the Montana hydroelectric generating facilities which were sold in 2011 compared with 2010.  The decrease in 2011 compared with 2010 was primarily due to the presentation of PPL Global as Discontinued Operations as a result of the January 2011 distribution by PPL Energy Supply of its membership interest in PPL Global to its parent, PPL Energy Funding.  In 2011, the results of PPL Global are no longer consolidated within PPL Energy Supply.November 2014.  See Note 96 to the Financial Statements for additional information.

Margins

Management utilizes "Margins," a non-GAAP financial measure, as an indicator of performance for its business.

"Margins" is defined as energy revenues offset by the cost of fuel, energy purchases, certain operation and maintenance expenses, primarily ancillary charges, and gross receipts tax, recorded in "Taxes, other than income." This performance measure is relevant due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs, RTOs and significant fluctuations in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy," "Retail energy" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by Talen Energy Marketing, which prior to June 1, 2015, are reflected in "Wholesale energy to affiliate" in the reconciliation table below. "Margins" excludes unrealized (gains) losses on: energy related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of the competitive generation assets, full-requirement sales contracts and retail activities; and trading activities. These derivatives are subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged or when realized. Energy related economic activity includes premium amortization associated with options. Unrealized gains and losses related to derivatives and premium amortization associated with options are deferred and included in "Margins" over the delivery period of the item that was hedged or upon realization.

This measure is not intended to replace "Operating Income (Loss)," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and report their results of operations. Management believes this measure provides additional useful criteria to make investment decisions. This

41

performance measure is used, in conjunction with other information, by senior management to manage Talen Energy's operations and analyze actual results compared with budget.

Reconciliation of Margins

The following tables contain the components from the Statements of Income that are included in Margins and a reconciliation to "Operating Income (Loss)" for the years ended December 31.
 2015 2014
 East Segment West Segment Reconciling Items (a) Operating Income (b) East Segment West Segment Reconciling Items (a) Operating Income (b)
Operating Revenues               
Wholesale energy$2,531
 $222
 $75 (c) $2,828
 $2,496
 $96
 $61 (c) $2,653
Wholesale energy to affiliate (d)14
 —
 —
 14
 84
 —
 —
 84
Retail energy1,039
 73
 (17) (c) 1,095
 1,135
 81
 27 (c) 1,243
Energy-related businesses—
 —
 544
 544
 —
 —
 601
 601
Total Operating Revenues3,584
 295

602

4,481

3,715
 177

689

4,581
                
Operating Expenses               
Fuel1,038
 120
 36 (c) 1,194
 1,097
 72
 27 (c) 1,196
Energy purchases723
 34
 (81) (c) 676
 971
 26
 57 (c) 1,054
Operation and maintenance16
 —
 1,036
 1,052
 22
 —
 985
 1,007
Impairments (Note 16)—
 —
 657
 657
 —
 —
 —
 —
Depreciation—
 —
 356
 356
 —
 —
 297
 297
Taxes, other than income41
 —
 24
 65
 43
 —
 14
 57
Energy-related businesses8
 —
 512
 520
 8
 —
 565
 573
Total Operating Expenses1,826
 154

2,540

4,520

2,141
 98

1,945

4,184
Total$1,758
 $141

$(1,938)
$(39) $1,574
 $79

$(1,256)
$397
 2013 
 East Segment West Segment Reconciling Items (a) Operating Income (b) 
Operating Revenues        
Wholesale energy$3,086
 $98
 $(294) (c) $2,890
 
Wholesale energy to affiliate (d)51
 —
 —
 51
 
Retail energy933
 82
 12 (c) 1,027
 
Energy-related businesses—
 —
 527
 527
 
Total Operating Revenues4,070
 180

245

4,495
 
         
Operating Expenses        
Fuel966
 78
 4 (c) 1,048
 
Energy purchases1,265
 23
 (135) (c) 1,153
 
Operation and maintenance20
 —
 941
 961
 
Loss on lease termination—
 —
 697
 697
 
Impairments—
 —
 65
 65
 
Depreciation—
 —
 299
 299
 
Taxes, other than income37
 —
 16
 53
 
Energy-related businesses7
 —
 505
 512
 
Total Operating Expenses2,295
 101

2,392

4,788
 
Total$1,775
 $79

$(2,147)
$(293) 
(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.
(c)
Includes unrealized gains (losses) on energy-related economic activity, which is subject to fluctuations in value due to market price volatility.  See "Commodity Price Risk (Non-trading) - Economic Activity" within Note 15 to the Financial Statements. Also includes unrealized gains (losses) on trading activity of $(37) million, $27 million and $(6) million for 2015, 2014 and 2013. Amounts have been adjusted for option premiums of $8 million and $(10) million for 2015 and 2014. To mitigate the risk of oversupply, Talen Energy incurred charges of $41 million during 2015 to reduce its contracted coal deliveries, which is also included in this amount. See Note 11 to the Financial Statements for additional information. 2015 also includes net realized gains on certain derivative contracts that were early-terminated of $13 million and a prior period revenue adjustment of $(7)

42

million. See Note 1 to the Financial Statements for additional information on the revenue adjustment. 2015, 2014 and 2013 includes OCI amortization on non-active derivative positions of $(11) million, $(11) million and $(13) million.
(d)Amounts recorded prior to the spinoff for activity with PPL Electric.

Changes in Margins

The following table shows Margins by segment for the years ended December 31, as well as the change between periods. Margins do not include operations related to those assets classified as discontinued operations. The factors that gave rise to the changes are described following the table.
   Change
 2015 2014 2013 2015 vs. 2014 2014 vs. 2013
East segment$1,758
 $1,574
 $1,775
 $184
 $(201)
West segment141
 79
 79
 62
 —
Total$1,899
 $1,653
 $1,854
 $246
 $(201)

East Segment

East segment Margins increased $162 million in 2015 from the Raven and Sapphire portfolios. There are no comparable amounts in the 2014 or 2013 periods as the acquisition of Raven and Sapphire occurred during 2015.

Excluding the impact of the Raven, Sapphire and MACH Gen acquisitions, East segment Margins increased in 2015 compared with 2014 by $22 million primarily due to higher realized energy prices of $68 million, improved spark spreads of $59 million, higher nuclear availability of $51 million and lower average fuel prices of $24 million, substantially offset by lower capacity prices of $55 million, gains realized in 2014 on certain commodity positions of $46 million, the net effect of unusual market and weather volatility in the first quarter of 2014 as discussed below of $38 million, lower volumes on full-requirement sales contracts of $25 million and retail electric activity of $12 million.

East segment Margins decreased in 2014 compared with 2013 primarily due to lower realized energy prices of $354 million and lower capacity prices of $34 million, partially offset by favorable asset performance of $70 million, gains realized in 2014 on certain commodity positions of $46 million, unusual market and weather volatility in 2014 as discussed below of $38 million and gas optimization of $26 million.

During the first quarter of 2014, the PJM region experienced unusually cold weather conditions, higher demand and congestion patterns, causing rising natural gas and electricity prices in spot and near-term forward markets. Due to these market dynamics, Talen Energy captured opportunities on unhedged generation, which were offset primarily by losses incurred by under-hedged full-requirement sales contracts and retail electric portfolios, which were not fully hedged or able to be fully hedged given the higher load conditions and lack of market liquidity.

West Segment

West segment Margins increased $68 million in 2015 compared with 2014 from the Jade portfolio. There are no comparable amounts in the 2014 and 2013 periods as the acquisition of Jade occurred during 2015.

EBITDA and Adjusted EBITDA

In addition to operating income (loss), EBITDA and Adjusted EBITDA, non-GAAP financial measures are other indicators of performance for Talen Energy's business, with Adjusted EBITDA as the primary financial performance measure used by management to evaluate its business and monitor results of operations.

EBITDA represents net income (loss) before interest expense, income taxes, depreciation and certain amortization. Adjusted EBITDA represents EBITDA further adjusted for certain non-cash and other items that management believes are not indicative of ongoing operations including, but not limited to, unrealized gains and losses on derivative contracts, stock-based compensation expense, asset retirement obligation accretion, impairments, gains and losses on securities in the NDT funds, gains or losses on sales, dispositions or retirements of assets, debt extinguishments and transition, transaction and restructuring costs.

EBITDA and Adjusted EBITDA are not intended to represent cash flows from operations, operating income (loss) or net income (loss) as defined by U.S. GAAP as indicators of operating performance and are not necessarily comparable to similarly-

43

titled measures reported by other companies. Management cautions investors that amounts presented in accordance with Talen Energy's definitions of EBITDA and Adjusted EBITDA may not be comparable to similar measures disclosed by other companies because not all companies calculate EBITDA and Adjusted EBITDA in the same manner. Talen Energy believes EBITDA and Adjusted EBITDA are useful to investors and other users of these financial statements in evaluating Talen Energy's operating performance because they provide additional tools to compare business performance across companies and across periods. Talen Energy believes that EBITDA is widely used by investors to measure a company's operating performance without regard to such items as interest expense, income taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, Talen Energy believes that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. Talen Energy adjusts for these and other items, as management believes that these items would distort their ability to efficiently view and assess the company's core operating trends. In summary, management primarily uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, as a measure of certain corporate financial goals used to determine variable compensation and in communications with the Talen Energy Corporation Board of Directors, senior management, shareholders, creditors, analysts and investors concerning Talen Energy's financial performance.

Reconciliations of EBITDA and Adjusted EBITDA

The tables below provide reconciliations of EBITDA and Adjusted EBITDA to operating income (loss) on a segment basis and to net income (loss) on a consolidated basis for the years ended December 31.

2015 2014

East Segment
West Segment
Other
Total East Segment West Segment Other Total
Net income (loss)





$(341)       $410
(Income) loss from discontinued operations (net of tax)





—
       (223)
Interest expense





211
       124
Income taxes





(27)       116
Other (income) expense - net





118
       (30)
Operating income (loss)$198

$2

$(239)
$(39) $558
 $71
 $(232) $397
Depreciation327

26

3

356
 296
 1
 —
 297
Other income (expense) - net19

(2)
(135)
(118) 29
 —
 1
 30
EBITDA$544

$26

$(371)
$199
 $883
 $72
 $(231) $724
Unrealized (gain) loss on derivative contracts (a)(175)
25

—

(150) 15
 (32) —
 (17)
Stock-based compensation expense (b)—

—

40

40
 —
 —
 18
 18
(Gain) loss from NDT funds(15)
—

—

(15) (26) —
 —
 (26)
ARO accretion33

1

—

34
 32
 —
 —
 32
Coal contract adjustment (c)41
 —
 —
 41
 —
 —
 —
 —
Impairments (d)657
 —
 —
 657
 —
 —
 —
 —
REPS Remarketing—
 —
 134
 134
 —
 —
 —
 —
Mechanical subsidiary revenue adjustment (e)—
 —
 —
 —
 (17) —
 —
 (17)
TSA costs—

—

29

29
 —
 —
 —
 —
Separation benefits (f)—

—

2

2
 —
 —
 33
 33
Corette closure costs (g)—

4

—

4
 —
 —
 —
 —
Terminated derivative contracts (h)(13)
—

—

(13) —
 —
 —
 —
Revenue adjustment (i)7

—

—

7
 —
 —
 —
 —
Transaction costs—

—

20

20
 —
 —
 —
 —
Restructuring costs (j)—

—

12

12
 —
 —
 1
 1
Other (k)1

—

—

1
 11
 —
 —
 11
Adjusted EBITDA$1,080

$56

$(134)
$1,002
 $898
 $40
 $(179) $759

44

 2013 
 East Segment West Segment Other Total 
Net income (loss)





$(230) 
(Income) loss from discontinued operations (net of tax)





(32) 
Noncontrolling interest      1
 
Interest expense





159
 
Income taxes





(159) 
Other (income) expense - net





(32) 
Operating income (loss)$652
 $(750) $(195)
$(293) 
Depreciation288
 11
 —
 299
 
Other income (expense) - net30
 —
 2

32
 
Noncontrolling interest(1) —
 —

(1) 
EBITDA$969

$(739)
$(193)
$37
 
Unrealized (gain) loss on derivative contracts (a)133
 3
 —

136
 
Stock-based compensation expense (b)—
 —
 16

16
 
(Gain) loss from NDT funds(22) —
 —

(22) 
ARO accretion29
 —
 —

29
 
Impairments (d)—
 65
 —
 65
 
Loss on lease termination (Note 6)—
 697
 —

697
 
Other (k)13
 (2) —

11
 
Adjusted EBITDA$1,122

$24

$(177)
$969
 
(a)Represents unrealized gains (losses) on derivatives. See "Commodity Price Risk (Non-trading) - Economic Activity" and "Commodity Price Risk (Trading)" in Note 15 to the Financial Statements for additional information on derivatives. Amounts have been adjusted for option premiums of $8 million and $(10) million for 2015 and 2014.
(b)2015 includes a charge for the acceleration of expense as a result of the spinoff. See Note 1 to the Financial Statements for additional information. For periods prior to June 2015, represents the portion of PPL's stock-based compensation cost allocable to Talen Energy. Amounts prior to June 2015 were cash settled with a former affiliate.
(c)To mitigate the risk of oversupply, Talen Energy incurred pre-tax charges of $41 million in 2015 in connection with an agreement to reduce its contracted coal deliveries. See Note 11 to the Financial Statements for additional information.
(d)2015 includes charges for goodwill and certain long-lived assets. 2013 includes a charge for the Corette plant and related emission allowances. See Notes 14 and 16 to the Financial Statements for additional information.
(e)In 2014, Talen Energy recorded $17 million to "Energy-related businesses" revenues related to prior periods and the timing of revenue recognition for a mechanical contracting and engineering subsidiary. See Note 1 to the Financial Statements for additional information.
(f)In June 2014, Talen Energy Supply's largest IBEW local ratified a new three-year labor agreement. In connection with the new agreement, estimated bargaining unit one-time voluntary retirement benefits of $17 million were recorded. In addition, 2014 includes separation costs of $16 million related to the spinoff transaction.
(g)Operations were suspended and the Corette plant was retired in March 2015.
(h)
Represents net realized gains on certain derivative contracts that were early-terminated due to the spinoff transaction.
(i)Relates to a prior period revenue adjustment for the receipt of revenue under a transmission operating agreement with Talen Energy Supply's former affiliate, PPL Electric. See Note 1 to the Financial Statements for additional information.
(j)Costs related to the spinoff transaction, including expenses associated with the FERC-required mitigation and legal and professional fees.
(k)All periods include OCI amortization on non-active derivative positions and 2015 includes a gain on the sale of Talen Renewable Energy.

Changes in Adjusted EBITDA

The following table shows Adjusted EBITDA by segment for the years ended December 31 as well as the change between periods. The factors that gave rise to the changes are described following the table.
   Change
 2015 2014 2013 2015 vs. 2014
2014 vs. 2013
     East$1,080
 $898
 $1,122
 $182
 $(224)
     West56
 40
 24
 16
 16
     Other(134) (179) (177) 45
 (2)
Total$1,002
 $759
 $969
 $243
 $(210)

45


East Segment

The increase in the East segment in 2015 compared with 2014 was primarily due to higher Margins driven by the addition of the Raven and Sapphire operations, higher realized energy prices, improved spark spreads, higher nuclear availability and lower average fuel prices. These factors were partially offset by lower capacity prices, gains that were realized in 2014 on certain commodity positions, the net effect of unusual market and weather volatility in the first quarter of 2014, lower volumes on full-requirements sales contracts, and retail electric sales activity. The net improvements in Margins were partially offset by higher operation and maintenance expenses, reflecting the addition of the Raven and Sapphire operations partially offset by lower outage costs for coal-fired units and other cost reductions attributable to the spinoff from PPL.

The decrease in the East segment in 2014 compared with 2013 was primarily due to lower Margins driven by lower realized energy and capacity prices, partially offset by favorable asset performance, gains on certain commodity positions and net benefits of unusual market and weather volatility in the first quarter of 2014.

West Segment

The increase in the West segment in 2015 compared with 2014 was primarily due to the addition of the Jade operations in Texas, partially offset by higher coal-fired plant outage costs.

The increase in the West segment in 2014 compared with 2013 was primarily due to the elimination of rent expense associated with the Colstrip lease, which was terminated in December 2013.

Other

The increase in 2015 compared with 2014 was primarily due to lower corporate expenses, which were primarily a result of cost reductions attributable to the spinoff from PPL.

See "Margins" and "Statement of Income Analysis" above for a more detailed analysis of the changes.

Financial Condition

Liquidity and Capital Resources

PPL Energy Supply expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances.  In 2013, PPL Energy Supply anticipates receiving capital contributions from its member, as well.

PPL Energy Supply'sTalen Energy's cash flows from operations and access to cost-effectivecost effective bank and capital markets are subject to risks and uncertainties including, but not limited to:

·changes in electricity, fuel and other commodity prices;
·operational and credit risks associated with selling and marketing products in the wholesale power markets;
·potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate PPL Energy Supply's risk exposure to adverse changes in electricity and fuel prices, interest rates and counterparty credit;
·reliance on transmission and distribution facilities that PPL Energy Supply does not own or control to deliver its electricity and natural gas;
·unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·costs of compliance with existing and new environmental laws and with new security and safety requirements for nuclear facilities;
·any adverse outcome of legal proceedings and investigations with respect to PPL Energy Supply's current and past business activities;
·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·a downgrade in PPL Energy Supply's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt.

uncertainties. See "Item 1A. Risk Factors" for furthera discussion of risks and uncertainties that could affect PPL Energy Supply'sTalen Energy's cash flows.

At December 31, PPLTalen Energy Supply had the following:
following at December 31:
  2012  2011  2010 
          
Cash and cash equivalents $ 413  $ 379  $ 661 
Short-term debt $ 356  $ 400  $ 531 

The changes in PPL Energy Supply's cash and cash equivalents position resulted from:

  2012  2011  2010 
          
Net cash provided by (used in) operating activities $ 784  $ 776  $ 1,840 
Net cash provided by (used in) investing activities   (469)   (668)   (825)
Net cash provided by (used in) financing activities   (281)   (390)   (612)
Effect of exchange rates on cash and cash equivalents         13 
Net Increase (Decrease) in Cash and Cash Equivalents $ 34  $ (282) $ 416 
102
Operating Activities
 2015 2014 2013
Cash and cash equivalents$141
 $352
 $239
Short-term debt608
 630
 —

Net cash provided by (used in) operating, investing, and financing activities increased by 1%, or $8 million, in 2012 compared with 2011.  This was primarily due to a $92 million decrease in net cash used in other operating activities (includes a $77 million reduction in defined benefit plan funding)for the years ended December 31 and a $23 million decrease in net cash used in working capital (including a changethe changes between periods were as follows.
 2015 2014 2013 2015 vs. 2014 2014 vs. 2013
Operating activities$768
 $462
 $410
 $306
 $52
Investing activities(915) 497
 (631) (1,412) 1,128
Financing activities(64) (846) 47
 782
 (893)


46

Operating Activities

NetThe components of the change in cash provided by (used in) operating activities decreased by 58%, or $1.1 billion, in 2011 compared with 2010.  This was primarily due to lower gross energy margins of $240 million, after-tax, proceeds from monetizing certain full-requirements sales contracts in 2010 of $249 million, a reduction in cash from counter party collateral of $172 million, increases in other operating outflows of $200 million (including higher operation and maintenance expenses and defined benefits funding of $123 million) and the loss of operating cash from PPL Global ($203 million for 2010).  In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent, PPL Energy Funding.  See Note 9 to the Financial Statements for additional information on the distribution.were as follows.
 2015 vs. 2014 2014 vs. 2013
Change - Cash Provided (Used)   
Net income$(751) $639
Non-cash components919
 (656)
Working capital199
 (46)
Defined benefit plan funding(39) 78
Other operating activities(22) 37
Total$306
 $52

A significant portion of PPL Energy Supply'sTalen Energy's operating cash flows is derived from its baseloadcompetitive generation business activities. PPLTalen Energy Supply employs a formal hedging program for its competitive baseload generation fleet, the primary objective of which is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term.term to benefit from power price increases. See Note 1915 to the Financial Statements for further discussion. Despite PPL Energy Supply'sTalen Energy's hedging practices, future cash flows from operating activities are influenced by commodityenergy and capacity prices and, therefore, will fluctuate from period to period.

PPL Energy Supply'sTalen Energy's contracts for the sale and purchase of electricity and fuel often require cash collateral or other credit enhancements,cash equivalents (e.g. letters of credit), or reductions or terminations of a portion of the entire contract through cash settlement, in the event of a downgrade of PPLTalen Energy Supply's or its subsidiary's credit ratings or adverse changes in market prices. For example, in addition to limiting its trading ability, if PPL Energy Supply's or its subsidiary's ratings were lowered to below "investment grade" and there was a 10% adverse movement in energy prices PPLor as a result of a downgrade in credit ratings, Talen Energy Supply estimates that, based on its December 31, 20122015 positions, it would have hadbeen required to post additional collateral of approximately $368$227 million with respect to electricity and fuel contracts. PPLTalen Energy Supplyhad adequate liquidity sources at December 31, 2015 if it would have been required to post this additional collateral. Talen Energy has in place risk management programs that are designed to monitor and manage its exposure to volatility of cash flows related to changes in energy and fuel prices, interest rates, foreign currency exchange rates, counterparty credit quality and the operating performance of its generating units.

Talen Energy had a $306 million increase in cash provided by operating activities in 2015 compared with 2014.

Net income (loss) decreased by $751 million between the periods. However, the decrease was more than offset by $919 million of non-cash components. The non-cash components consisted primarily of an increase in goodwill and other asset impairments of $642 million, a decrease in gains on the sale of assets of $306 million, an increase in non-cash amortization of $59 million, partially offset by an increase in unrealized gains on hedging and other hedging activities of $123 million. The increase in cash from operating activities from changes in working capital was partially due to a decrease in accounts receivable, fuel, materials and supplies, prepayments and increases in counterparty collateral (due in part to market price movement), partially offset by decreases in accounts payable. The decrease in fuel, materials and supplies related to increases that occurred in 2014 from coal inventory build-up and increases in fuel oil inventory at higher average prices. The decrease to accounts payable was related to the timing of certain plant outage payments, the change in market prices of gas and the settlement of the PPL affiliated accounts payable in advance of the June 1, 2015 spinoff. The decrease in prepayments was primarily due to income tax payments made in 2014.

Pension funding was $39 million higher in 2015.

Talen Energy had a $52 million increase in cash provided by operating activities in 2014 compared with 2013.

Net income improved by $639 million between the periods, however, this included an additional $656 million of net non-cash benefits, including a $315 million pre-tax gain in 2014 on the sale of the Montana hydroelectric generating facilities, a $426 million charge in 2013 to terminate the operating lease arrangement for interests in the Montana Colstrip facility and acquire the previously leased interests, and $167 million of lower unrealized losses on hedging activities. These non-cash benefits were partially offset by a $270 million decrease in deferred income tax benefits. The net $17 million decline from net income and non-cash adjustments in 2014 compared with 2013 reflects lower Margins, higher operation and maintenance expenses and other factors. Cash provided by operating activities in 2014 included a $176 million payment to PPL in November 2014 to satisfy the tax liability related to the gain on the sale of the Talen Montana hydroelectric facilities. Cash provided by operating activities in 2013 included a $271 million

47

payment in December in connection with terminating the operating lease arrangement for interests in the Montana Colstrip facility and acquiring the previously leased interests.
Pension funding was $78 million lower in 2014.

Investing Activities

The primary usecomponents of the change in cash inprovided by (used in) investing activities is capital expenditures.  See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.were as follows
 2015 vs. 2014 2014 vs. 2013
Change - Cash Provided (Used)   
  Expenditures for PP&E$(35) $167
  Acquisitions & divestitures, net(1,387) 900
  Restricted cash and cash equivalent activity195
 (86)
  Purchase and sale of investments, net—
 (1)
  Other investing activities(185) 148
Total$(1,412) $1,128

Net cash used in investing activities decreased $199 million in 2012In 2015 compared with 2011,2014, "Acquisitions & divestitures, net" primarily as a resultreflects the November 2015 purchase of a $396MACH Gen for $603 million change in notes receivableand 2014 includes proceeds from affiliates and a $232 million change in restricted cash and cash equivalents,the sale of the Talen Montana hydroelectric generating facilities, partially offset by $381proceeds of $116 million less in asset sale proceeds (2011from the sale of non-core generation facilities) and $84 million used to fund the 2012 Ironwood Acquisition (seeTalen Renewable Energy in November 2015. See Note 106 to the Financial Statements for additional information on this acquisition).

Netthe acquisition and divestitures. The change in "Restricted cash usedand cash equivalent activity" relates to collateral requirements to support Talen Energy's commodity hedging program. This change is primarily due to changes in forward energy commodity prices. The change in "Other investing activities decreased $157 million in 2011 compared with 2010,activities" was primarily as a result of a decrease of $348 million in capital expenditures and a $219 million increase in the proceeds received from the sale of businesses, which are discussed in Note 9due to the Financial Statements.  The decrease in cash used in investing activities from the above items was partially offset by an increase2014 receipt of $198$164 million related to notes receivable from affiliatesa U.S. Department of the Treasury grant for the Rainbow Dam and $212 million from changes in restricted cash and cash equivalents.Holtwood hydroelectric expansion capital projects.

In January 2011, PPL Energy Supply distributed its 100% membership interest2014 compared with 2013, the decrease in PPL Global"Expenditures for PP&E" was partially due to its parent, PPL Energy Funding.expenditures made in 2013 for the Holtwood hydroelectric expansion project. "Acquisitions & divestitures, net" reflects the 2014 sale of the Talen Montana hydroelectric generating facilities. See Note 96 to the Financial Statements for additional information.  Excluding PPL Global, PPL Energy Supply's net cash usedinformation on the sale. The change in "Other investing activitiesactivities" was $544due to the receipt of $164 million in 2014 from U.S. Department of Treasury grants for 2010.the Rainbow Dam and Holtwood hydroelectric expansion capital projects.
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Financing Activities

NetThe components of the change in cash usedprovided by (used in) financing activities were as follows.
 2015 vs. 2014 2014 vs. 2013
Change - Cash Provided (Used)   
Capital contributions from/distributions to predecessor member, net$1,032
 $(2,336)
Debt issuances/redemptions, net574
 438
Change in short-term debt, net(792) 986
Other(32) 19
Total$782
 $(893)

Talen Energy required $783 million less in financing activities was $281 million in 2012sources for 2015 compared with $390 million2014. In 2015, as a result of the terms of the spinoff transaction, the improvement in 2011 and $612 millioncapital contributions/distributions to predecessor member, net resulted from a reduction in 2010.  The decrease from 2011 to 2012 primarily reflects the 2011 distribution of cash included in the net assets of PPL Global toactivity with PPL Energy Funding and a decreaseCorporation. Changes in net retirement of long-term debt, partially offset by higher net distributions to Member.  The decrease from 2010 to 2011 primarily reflects lower net distributions to Member, partially offset by lower net issuances of long-term debt and the distribution of cash included in the net assets of PPL Global to PPL Energy Funding.

In 2012, cash used in financing activities primarily consisted of $787 million in distributionsrelated to Member and a $44 million net decrease in short-term debt partially offset by $563resulted from proceeds from 2014 borrowings of $630 million that were needed at that time to fund increased collateral requirements to support Talen Energy's commodity hedging program that were then repaid in contributions from Member.

In 2011, cash used in financing activities primarily consisted2015 using the $591 million of a $325 million distribution of cash included in the net assets of PPL Global to PPL Energy Funding, $316 million in distributions to Member, and net debt retirements of $200 million, partially offset by $461 million in contributions from Member.

In 2010, cash used in financing activities primarily consisted of $4.7 billion in distributions to Member, partially offset by $3.6 billion in contributions from Member and net debt issuances of $509 million.  The distributions to and contributions from Member during 2010 primarily relate to the funds received by PPL in June 2010proceeds from the issuance of common stocklong-term debt. In addition, in 2015, in connection with the RJS Power acquisition, $38 million of short-term debt borrowings under the then-outstanding RJS Power Holdings, LLC credit facility were repaid and 2010 Equity Units.  These funds were invested bythe facility was terminated in connection with the acquisition.

In 2014, financing activities included distributions of $836 million to PPL of the proceeds from the Talen Montana hydroelectric generating facilities sale, net of a subsidiarytax liability payment and proceeds from the U.S. Department of Treasury grant for the Holtwood hydroelectric expansion capital project.


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In 2013, financing activities included net capital contributions of $1.1 billion from PPL Energy Funding Corporation to Talen Energy Supply until they were returned to its Memberfund debt maturities, repay short-term debt and terminate the operating lease arrangement for interests in October 2010the Montana Colstrip facility and acquire the previously leased interests. Debt repayments included a $300 million debt maturity and the $437 million repayment by an unconsolidated trust of outstanding debt related to be available to partially fund PPL'sthe acquisition of LKE and pay certain acquisition-related fees and expenses.the previously leased Lower Mt. Bethel facility.

See "Long-term Debt and Equity Securities" below for additional information on current year activity. See "Forecasted Sources of Cash" for a discussion of PPL Energy Supply'sTalen Energy's plans to issue debt securities,access the capital markets, as well as a discussion of credit facility capacity available to PPLTalen Energy Supply. Also see "Forecasted Uses of Cash" for information regardinga discussion of Talen Energy Supply's and a subsidiary's maturities of PPL Energy Supply's long-term debt.

Long-term Debt and Equity Securities

Talen Energy activity for 2015 included:
  Debt Stock Issuances
  Issuances (a) Retirements 
       
Cash Transactions $600
 $335
 $—
Non-cash Transactions (b) 1,950
 231
 902

(a)Issuances are net of pricing discounts, where applicable and excludes the impact of debt issuance costs.
(b)"Debt Issuances" include long-term debt that remained outstanding as part of the RJS Power and MACH Gen acquisitions and the remarketing and exchange of PEDFA debt. "Retirements" represents the remarketing and exchange of PEDFA debt. "Stock Issuances" only applies to Talen Energy Corporation and includes common stock issued to the Riverstone Holders in connection with the RJS Power acquisition based on the June 1, 2015 closing "when-issued" market price.

See Note 5 to the Financial Statements for additional information about long-term debt securities and Note 1 to the Financial Statements for additional information on equity issued as part of the spinoff from PPL and simultaneous acquisition of RJS Power.

Forecasted Sources of Cash

PPLTalen Energy Supply expects to continue to have sufficient sources ofadequate liquidity available in the near term, includingfrom operating cash flows, from operations, variouscash and cash equivalents and credit facilities, commercial paper issuances, operating leases and contributions from member.arrangements. Additionally, although Talen Energy currently does not plan to access the capital markets, it may decide to do so based on market conditions. The discussion below regarding credit arrangements of Talen Energy Supply apply to Talen Energy Corporation through consolidation.

Revolving Credit Facilities

At December 31, 2012, PPLTalen Energy Supply'sSupply and a subsidiary maintain credit facilities to enhance liquidity and provide credit support.  The amounts "Borrowed" below are recorded as "Short-term debt" on the Balance Sheets.  The total committed borrowing capacity under outstanding credit facilities and the use of this borrowing capacity at December 31, were:
 2015 2014
 
Committed
Capacity
 Borrowed Letters of Credit Issued 
Unused
Capacity
 Committed Capacity Borrowed Letters of Credit Issued Unused Capacity
Credit Facilities$2,010
 $608
 $194
 $1,208
 $3,150
 $630
 $259
 $2,261

         Letters of   
         Credit   
         Issued   
         and   
         Commercial   
   Committed    Paper Unused
   Capacity Borrowed Backup Capacity
              
Syndicated Credit Facility (a) $ 3,000     $ 499  $ 2,501 
Letter of Credit Facility   200   n/a   132    68 
Total PPL Energy Supply Credit Facilities (b) $ 3,200     $ 631  $ 2,569 
On June 1, 2015, in connection with the completion of the spinoff transaction, Talen Energy Supply entered into the Talen Energy Supply RCF and replaced Talen Energy Supply's previously existing $3 billion unsecured syndicated credit facility that existed at December 31, 2014. At December 31, 2014, the $630 million of outstanding principal amount under the old facility was repaid prior to the termination of the old facility and any outstanding letters of credit were transferred to the Talen Energy Supply RCF.
The Talen Energy Supply RCF provides capacity for letters of credit and short-term borrowings and requires Talen Energy Supply to maintain a senior secured net debt to adjusted EBITDA ratio (as defined in the agreement) of less than or equal to 4.50 to 1.00 as of the last day of any fiscal quarter. Talen Energy Supply pays customary fees on the facility and borrowings bear interest at its option at either a defined base rate or LIBOR-based rates, in each case plus an applicable margin.

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(a)This facility contains a financial covenant requiring PPL Energy Supply's debt to total capitalization not to exceed 65%, as calculated in accordance with the facility, and other customary covenants.
Table of Contents

The commitments at December 31, 2015 under the Talen Energy Supply RCF are provided by a diverse bank group, with no one bank or its affiliates providing an aggregate commitment of more than 8% of the total committed capacity. In February 2016, Talen Energy repaid all $600 million of its then-outstanding short-term debt obligations under the Talen Energy Supply RCF, primarily with cash proceeds from the sale of Ironwood.  
(b)The commitments under PPL Energy Supply's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 11% of the total committed capacity.

The New MACH Gen RCF remained outstanding after the November 2015 MACH Gen acquisition. The New MACH Gen RCF provides capacity for short-term borrowings and up to $120 million of letters of credit. New MACH Gen pays customary fees on the facility and borrowings bear interest at 12-month LIBOR plus an applicable margin.
In addition to the financial covenants noted above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPLTalen Energy Supply monitors compliance with the covenants on a regular basis. At December 31, 2012, PPL2015, Talen Energy Supply was in compliance with these covenants. At this time PPLTalen Energy Supply believes that these covenants and other borrowing conditions will not limit access to these funding sources.

Other Facilities

Talen Energy Supply maintains a $1.3 billion secured energy marketing and trading facility whereby Talen Energy Supply will receive credit to be applied to satisfy collateral posting obligations related to Talen Energy's energy marketing and trading activities with counterparties participating in the facility.

See Note 75 to the Financial Statements for further discussion of PPL Energy Supply'sTalen Energy's credit facilities.
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Commercial Paperand other arrangements.

PPL Energy Supply maintains a $750 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility.  At December 31, 2012, PPL Energy Supply had $356 million of commercial paper outstanding at a weighted-average interest rate of approximately 0.50%.

Operating Leases

PPL Energy Supply and its subsidiaries also have available funding sources that are provided through operating leases.  PPL Energy Supply's subsidiaries lease office space, land, buildings and certain equipment.  These leasing structures provide PPL Energy Supply additional operating and financing flexibility.  The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.

PPL Energy Supply, through its subsidiary PPL Montana, leases a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3, under four 36-year, non-cancelable operating leases.  These operating leases are not recorded on PPL Energy Supply's Balance Sheets.  The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assets and declare dividends.

See Note 11 to the Financial Statements for further discussion of the operating leases.

Contributions from Member

From time to time, PPL Energy Supply's Member, PPL Energy Funding, makes capital contributions to PPL Energy Supply.  PPL Energy Supply uses these contributions to fund capital expenditures and for other general corporate purposes.

Forecasted Uses of Cash

In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, PPLTalen Energy Supply currently expects to incur future cash outflows for capital expenditures, various contractual obligations distributions to its Member and possibly thecould purchase or redemption ofredeem a portion of its or a subsidiary's outstanding debt securities.

Capital Expenditures

The table below shows PPL Energy Supply'sTalen Energy's current capital expenditure projections for the years 20132016 through 2017.2020.
    Projected
  Total 2016 2017 2018 2019 2020
             
Sustenance $1,310
 $233
 $305
 $295
 $257
 $220
Nuclear fuel 608
 82
 114
 132
 137
 143
Growth 113
 108
 3
 1
 1
 —
Information technology 120
 54
 15
 20
 17
 14
Environmental 137
 17
 15
 16
 50
 39
Regulatory 61
 26
 26
 8
 1
 —
Discretionary 31
 6
 6
 7
 6
 6
Total (a) (b) $2,380
 $526
 $484
 $479
 $469
 $422

    Projected
    2013  2014  2015  2016  2017 
Construction expenditures (a) (b)               
 Generating facilities $ 387  $ 248  $ 247  $ 241  $ 292 
 Environmental   94    89    22    20    21 
 Other   26    34    15    15    15 
  Total Construction Expenditures   507    371    284    276    328 
Nuclear fuel   152    145    153    158    162 
Total Capital Expenditures $ 659  $ 516  $ 437  $ 434  $ 490 

(a)Construction expendituresDoes not include the Holtwood and Lake Wallenpaupack hydroelectric projects, the Ironwood natural gas combined-cycle plant, and the C.P. Crane coal-fired power plant, which have been sold or are under an agreement to sell. See Note 6 to the Financial Statements for additional information on the divestitures.
(b)Includes capitalized interest, which, over all years, is expected to total approximately $82 million for the years 2013 through 2017.$60 million.
(b)Includes expenditures for certain intangible assets.

PPL Energy Supply's capital expenditure projections for the years 2013 through 2017 total approximately $2.5 billion.  Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.  This table includes projected costs related to the planned 153 MW of incremental capacity increases.  See Note 8 to the Financial Statements for information regarding the significant development projects.

PPL Energy Supply plans to fund its capital expenditures in 2013 with cash from operations and equity contributions from PPL Energy Funding.

Contractual Obligations

PPL Energy Supply has assumed various financial obligations and commitments in the ordinary course of conducting its business.  At December 31, 2012, the estimated contractual cash obligations of PPL Energy Supply were:
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   Total 2013  2014 - 2015 2016 - 2017 After 2017
                 
Long-term Debt (a) $ 3,249  $ 751  $ 635  $ 386  $ 1,477 
Interest on Long-term Debt (b)   1,169    196    265    167    541 
Operating Leases (c)   362    76    143    39    104 
Purchase Obligations (d)   3,047    863    878    696    610 
Other Long-term Liabilities               
 Reflected on the Balance               
 Sheet under GAAP (e) (f)   105    105          
Total Contractual Cash Obligations $ 7,932  $ 1,991  $ 1,921  $ 1,288  $ 2,732 

(a)Reflects principal maturities only based on stated maturity dates, except for the 5.70% REset Put Securities (REPS).  See Note 7 to the Financial Statements for a discussion of the remarketing feature related to the REPS, as well as discussion of variable-rate remarketable bonds.  PPL Energy Supply does not have any significant capital lease obligations.
(b)Assumes interest payments through stated maturity, except for the REPS, for which interest is reflected to the put date.  The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)See Note 11 to the Financial Statements for additional information.
(d)The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.  Primarily includes PPL Energy Supply's purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the Capital Expenditures table presented above.  Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented.
(e)The amounts represent contributions made or committed to be made for 2013 for PPL's U.S. pension plans.  See Note 13 to the Financial Statements for a discussion of expected contributions.
(f)At December 31, 2012, total unrecognized tax benefits of $30 million were excluded from this table as PPL Energy Supply cannot reasonably estimate the amount and period of future payments.  See Note 5 to the Financial Statements for additional information.

Distributions to Member

From time to time, as determined by its Board of Managers, PPL Energy Supply makes distributions to its member.

Purchase or Redemption of Debt Securities

PPL Energy Supply will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.

Rating Agency Actions

Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of PPL Energy Supply and its subsidiaries.  Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.

A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues.  The credit ratings of PPL Energy Supply and its subsidiaries are based on information provided by PPL Energy Supply and other sources.  The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL Energy Supply or its subsidiaries.  Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.  The credit ratings of PPL Energy Supply and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.

The following table sets forth PPL Energy Supply's and its subsidiaries' security credit ratings as of December 31, 2012.

Senior UnsecuredSenior SecuredCommercial Paper
IssuerMoody'sS&PFitchMoody'sS&PFitchMoody'sS&PFitch
PPL Energy SupplyBaa2BBBBBBP-2A-2F-2
PPL IronwoodB2B
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A downgrade in PPL Energy Supply's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets.  PPL Energy Supply and its subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.

In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL Energy Supply and its subsidiaries in 2012.

In January 2012, S&P affirmed its rating and revised its outlook, from positive to stable, for PPL Montana's Pass Through Certificates due 2020.

Following the announcement of the then-pending acquisition of AES Ironwood, L.L.C. in February 2012, the rating agencies took the following actions:

·In March 2012, Moody's placed AES Ironwood, L.L.C.'s senior secured bonds under review for possible ratings upgrade.

·In April 2012, S&P affirmed the rating of AES Ironwood, L.L.C.'s senior secured bonds.

In May 2012, Fitch downgraded its rating, from BBB to BBB- and revised its outlook, from negative to stable, for PPL Montana's Pass Through Certificates due 2020.

In November 2012, S&P revised its outlook, from stable to negative, for PPL Montana's Pass Through Certificates due 2020.

In December 2012, Fitch affirmed the issuer default rating, individual security rating and revised the outlook, from stable to negative, for PPL Energy Supply.

In February 2013, Moody's upgraded its rating, from Ba1 to B2, and revised the outlook from under review to stable for PPL Ironwood.

Ratings Triggers

PPL Energy Supply has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, tolling agreements and interest rate instruments, which contain provisions that require PPL Energy Supply to post additional collateral, or permit the counterparty to terminate the contract, if PPL Energy Supply's credit rating were to fall below investment grade.  See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012.  At December 31, 2012, if PPL Energy Supply's credit rating had been below investment grade, PPL Energy Supply would have been required to prepay or post an additional $385 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate contracts.

Guarantees for Subsidiaries

PPL Energy Supply guarantees certain consolidated affiliate financing arrangements that enable certain transactions.  Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, require early maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions.  At this time, PPL Energy Supply believes that these covenants will not limit access to relevant funding sources.  See Note 15 to the Financial Statements for additional information about guarantees.

Off-Balance Sheet Arrangements

PPL Energy Supply has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party.  See Note 15 to the Financial Statements for a discussion of these agreements.

Risk Management - Energy Marketing & Trading and Other

Market Risk

See Notes 1, 18, and 19 to the Financial Statements for information about PPL Energy Supply's risk management objectives, valuation techniques and accounting designations.
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The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions.  Actual future results may differ materially from those presented.  These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.

Commodity Price Risk (Non-trading)

PPL Energy Supply segregates its non-trading activities into two categories:  hedge activity and economic activity.  Transactions that are accounted for as hedge activity qualify for hedge accounting treatment.  The economic activity category includes transactions that address a specific risk, but were not eligible for hedge accounting or for which hedge accounting was not elected.  This activity includes the changes in fair value of positions used to hedge a portion of the economic value of PPL Energy Supply's competitive generation assets and full-requirement sales and retail contracts.  This economic activity is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power).  Although they do not receive hedge accounting treatment, these transactions are considered non-trading activity.  The net fair value of economic positions at December 31, 2012 and 2011 was a net asset/(liability) of $346 million and $(63) million.  See Note 19 to the Financial Statements for additional information.

To hedge the impact of market price volatility on PPL Energy Supply's energy-related assets, liabilities and other contractual arrangements, PPL Energy Supply both sells and purchases physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enters into financial exchange-traded and over-the-counter contracts.  PPL Energy Supply's non-trading commodity derivative contracts range in maturity through 2019.

The following table sets forth the changes in the net fair value of non-trading commodity derivative contracts at December 31, 2012.  See Notes 18 and 19 to the Financial Statements for additional information.

  Gains (Losses)
  2012  2011 
       
Fair value of contracts outstanding at the beginning of the period $ 1,082  $ 958 
Contracts realized or otherwise settled during the period   (1,005)   (523)
Fair value of new contracts entered into during the period (a)   7    13 
Other changes in fair value   389    634 
Fair value of contracts outstanding at the end of the period $ 473  $ 1,082 

(a)Represents the fair value of contracts at the end of the quarter of their inception.

The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2012, based on the level of observability of the information used to determine the fair value.

   Net Asset (Liability)
   Maturity       Maturity   
   Less Than Maturity Maturity in Excess Total Fair
   1 Year 1-3 Years 4-5 Years of 5 Years Value
Source of Fair Value               
Prices based on significant observable inputs (Level 2) $ 452  $ 15  $ (20) $ 5  $ 452 
Prices based on significant unobservable inputs (Level 3)   8    10    3       21 
Fair value of contracts outstanding at the end of the period $ 460  $ 25  $ (17) $ 5  $ 473 

PPL Energy Supply sells electricity, capacity and related services and buys fuel on a forward basis to hedge the value of energy from its generation assets.  If PPL Energy Supply were unable to deliver firm capacity and energy or to accept the delivery of fuel under its agreements, under certain circumstances it could be required to pay liquidating damages.  These damages would be based on the difference between the market price and the contract price of the commodity.  Depending on price changes in the wholesale energy markets, such damages could be significant.  Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties (or their counterparties) with which it has energy contracts and other factors could affect PPL Energy Supply's ability to meet its obligations, or cause significant increases in the market price of replacement energy.  Although PPL Energy Supply attempts to mitigate these risks, there can be no assurance that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future.  In connection with its bankruptcy proceedings, a significant counterparty, SMGT, had been purchasing lower volumes of electricity than prescribed in the contract and effective April 1, 2012 the contract was terminated.  PPL Energy Supply cannot predict the prices or other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of this contract.  See Note 15 to the Financial Statements for additional information.
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Commodity Price Risk (Trading)

PPL Energy Supply's trading commodity derivative contracts range in maturity through 2017.  The following table sets forth changes in the net fair value of trading commodity derivative contracts at December 31, 2012 .  See Notes 18 and 19 to the Financial Statements for additional information.

   Gains (Losses)
   2012  2011 
        
Fair value of contracts outstanding at the beginning of the period $ (4) $ 4 
Contracts realized or otherwise settled during the period   20    (14)
Fair value of new contracts entered into during the period (a)   17    10 
Other changes in fair value   (4)   (4)
Fair value of contracts outstanding at the end of the period $ 29  $ (4)

 (a)Represents the fair value of contracts at the end of the quarter of their inception.

The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2012, based on the level of observability of the information used to determine the fair value.

   Net Asset (Liability)
   Maturity       Maturity   
   Less Than Maturity Maturity in Excess Total Fair
   1 Year 1-3 Years 4-5 Years of 5 Years Value
Source of Fair Value               
Prices based on significant observable inputs (Level 2) $ 18  $ 10        $ 28 
Prices based on significant unobservable inputs (Level 3)   1             1 
Fair value of contracts outstanding at the end of the period $ 19  $ 10        $ 29 

VaR Models

A VaR model is utilized to measure commodity price risk in domestic gross energy margins for its non-trading and trading portfolios.  VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level.  VaR is calculated using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level.  Given the company's disciplined hedging program, the non-trading VaR exposure is expected to be limited in the short-term.  The VaR for portfolios using end-of-month results for the period was as follows.

   Trading VaR Non-Trading VaR
   2012  2011  2012  2011 
95% Confidence Level, Five-Day Holding Period            
 Period End $ 2  $ 1  $ 12  $ 6 
 Average for the Period   3    3    10    5 
 High   8    6    12    7 
 Low   1    1    7    4 

The trading portfolio includes all proprietary trading positions, regardless of the delivery period.  All positions not considered proprietary trading are considered non-trading.  The non-trading portfolio includes the entire portfolio, including generation, with delivery periods through the next 12 months.  Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets.  The fair value of the non-trading and trading FTR positions was insignificant at December 31, 2012.

Interest Rate Risk

PPL Energy Supply and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk.  PPL and PPL Energy Supply utilize various financial derivative instruments to adjust the mix of fixed and floating interest rates in PPL Energy Supply's debt portfolio, adjust the duration of its debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate.  Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL Energy Supply's debt portfolio due to changes in the absolute level of interest rates.

At December 31, 2012 and 2011, PPL Energy Supply's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
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PPL Energy Supply is also exposed to changes in the fair value of its debt portfolio.  PPL Energy Supply estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $52 million, compared with $53 million at December 31, 2011.

NDT Funds - Securities Price Risk

In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the PPL Susquehanna nuclear plant (Susquehanna).  At December 31, 2012, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on PPL Energy Supply's Balance Sheet.  The mix of securities is designed to provide returns sufficient to fund Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs.  However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates.  PPL actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement.  At December 31, 2012, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $49 million reduction in the fair value of the trust assets, compared with $43 million at December 31, 2011.  See Notes 18 and 23 to the Financial Statements for additional information regarding the NDT funds.

Defined Benefit Plans - Securities Price Risk

See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on plan assets.

Credit Risk

Credit risk is the risk that PPL Energy Supply would incur a loss as a result of nonperformance by counterparties of their contractual obligations.  PPL Energy Supply maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk.  However, PPL Energy Supply has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies.  These concentrations may impact PPL Energy Supply's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.

PPL Energy Supply includes the effect of credit risk on its fair value measurements to reflect the probability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint).  In this case, PPL Energy Supply would have to sell into a lower-priced market or purchase from a higher-priced market.  When necessary, PPL Energy Supply records an allowance for doubtful accounts to reflect the probability that a counterparty will not pay for deliveries PPL Energy Supply has made but not yet billed, which are reflected in "Unbilled revenues" on the Balance Sheets.  PPL Energy Supply also has established a reserve with respect to certain receivables from SMGT, which is reflected in accounts receivable on the Balance Sheets.  See Note 15 to the Financial Statements for additional information.

See "Overview" in this Item 7 and Notes 16, 18 and 19 to the Financial Statements for additional information on credit concentration and credit risk.

Related Party Transactions

PPL Energy Supply is not aware of any material ownership interests or operating responsibility by senior management of PPL Energy Supply in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL Energy Supply.  See Note 16 to the Financial Statements for additional information on related party transactions.

Acquisitions, Development and Divestitures

PPL Energy Supply from time to time evaluates opportunities for potential acquisitions, divestitures and development projects.  Development projects are reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.

Incremental capacity increases of 153 MW are currently planned, primarily at existing PPL Energy Supply generating facilities.  See "Item 2. Properties - Supply Segment" for additional information.

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See Notes 8 and 9 to the Financial Statements for additional information on the more significant activities, including the 2012 Ironwood Acquisition.

Environmental Matters

Extensive federal, state and local environmental laws and regulations are applicable to PPL Energy Supply's air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the cost of compliance or alleged non-compliance cannot be predicted with certainty but could be material.  In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed by the relevant agencies.  Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or other restrictions.  Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost of their products or their demand for PPL Energy Supply's services.

Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL Energy Supply's generation assets as well as impacts on customers.  In addition, changed weather patterns could potentially reduce annual rainfall in areas where PPL Energy Supply has hydro generating facilities or where river water is used to cool its fossil and nuclear powered generators.  PPL Energy Supply cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.

The below provides a discussion of the more significant environmental matters.

Coal Combustion Residuals (CCRs)
In June 2010, the EPA proposed two approaches to regulating CCRs (as either hazardous or non-hazardous) under existing solid waste regulations.  A final rulemaking is currently expected before the end of 2015.  However, the timing of the final regulations could be accelerated by certain litigation that could require the EPA to issue its regulations sooner.  Regulations could impact handling, disposal and/or beneficial use of CCRs.  The economic impact could be material if CCRs are regulated as hazardous waste, and significant if regulated as non-hazardous, in accordance with the proposed rule.

Effluent Limitation Guidelines
The EPA is to issue guidelines for technology-based limits in discharge permits for scrubber wastewater and is expected to require dry ash handling.  The EPA agreed, in recent settlement negotiations with environmentalists, to propose revisions to its effluent limitation guidelines (ELGs) by April 2013, with a final rule in late 2014.  Limits could be so stringent that plants may consider extensive new or modified wastewater treatment facilities and possibly zero liquid discharge operations, the cost of which could be significant.  Impacts should be better understood after the proposed rule is issued.

316(b) Cooling Water Intake Structures Rule
In April 2011, the EPA published a draft regulation under Section 316(b) of the Clean Water Act, which regulates cooling water intakes for power plants.  The draft rule has two provisions: one requires installation of Best Technology Available (BTA) to reduce mortality of aquatic organisms that are pulled into the plants cooling water system (entrainment), and the second imposes standards for reduction of mortality of aquatic organisms trapped on water intake screens (impingement).  A final rule is expected in June 2013.  The proposed regulation would apply to nearly all PPL Energy Supply-owned steam electric plants in Pennsylvania and Montana, potentially even including those equipped with closed-cycle cooling systems.  PPL Energy Supply's compliance costs could be significant, especially if the final rule requires closed-cycle systems at plants that do not currently have them or conversions of once-through systems to closed-cycle.

GHG Regulations
In 2013, the EPA is expected to finalize limits on GHG emissions from new power plants and to begin working on a proposal for such emissions from existing power plants.  The EPA's proposal on GHG emissions from new power plants would effectively preclude construction on any coal-fired plants and could even be difficult for new gas-fired plants to meet.  With respect to existing power plants, the impact could be very significant, depending on the structure and stringency of the final rule.  PPL Energy Supply, along with others in the industry, filed comments on the EPA's proposal related to GHG emissions from new plants.  With respect to GHG limits for existing plants, PPL Energy Supply will advocate for reasonable, flexible requirements.
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MATS
The EPA finalized MATS requiring fossil-fuel fired plants to reduce emissions of mercury and other hazardous air pollutants by April 16, 2015.  The rule is being challenged by industry groups and states.  The EPA has subsequently proposed changes to the rule with respect to new sources to address the concern that the rule effectively precludes new coal plants.  PPL Energy Supply is generally well-positioned to comply with MATS due to its recent investment in, and installation of, environmental controls such as wet flue gas desulfurization systems.  PPL Energy Supply is evaluating chemical additive systems for mercury control at Brunner Island, and modifications to existing controls at Colstrip for improved particulate matter reductions.  In September 2012, PPL Energy Supply announced its intention to place its Corette plant in long-term reserve status beginning in April 2015 due to expected market conditions and costs to comply with MATS.

CSAPR and CAIR
In 2011, the EPA finalized its CSAPR regulating emissions of nitrous oxide and sulfur dioxide through new allowance trading programs which were to be implemented in two phases (2012 and 2014).  Like its predecessor, the CAIR, CSAPR targeted sources in the eastern United States.  In December 2011, the Court of Appeals for the D.C. Circuit (the Court) stayed implementation of CSAPR, leaving CAIR in place.  Subsequently, in August 2012, the Court vacated and remanded CSAPR back to the EPA for further rulemaking, again leaving CAIR in place, pending further EPA action.  PPL Energy Supply plants in Pennsylvania will continue to comply with CAIR through optimization of existing controls, balanced with emission allowance purchases.  The Court's August decision leaves plants in CSAPR-affected states potentially exposed to more stringent emission reductions due to regional haze implementation (it was previously determined that CSAPR or CAIR participation satisfies regional haze requirements), and/or petitions to the EPA by downwind states under Section 126 of the Clean Air Act requesting the EPA to require plants that allegedly contribute to downwind non-attainment to take action to reduce emissions.

Regional Haze - Montana
The EPA signed its final Federal Implementation Plan (FIP) of the Regional Haze Rules for Montana in September 2012, with tighter emissions limits for Colstrip Units 1 & 2 based on the installation of new controls (no limits or additional controls were specified for Colstrip Units 3 & 4), and tighter emission limits for Corette (which are not based on additional controls).  The cost of the potential additional controls for Colstrip Units 1 & 2, if required, could be significant.  PPL Energy Supply expects to meet the tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" discussion above).

See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for additional information on environmental matters.

Competition

See "Item 1. Business - Segment Information - Supply Segment - Competition" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting PPL Energy Supply.

New Accounting Guidance

See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.

Application of Critical Accounting Policies

Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies.  The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain.  Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements).  Senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.

Price Risk Management

See "Price Risk Management" in Note 1 to the Financial Statements, as well as "Risk Management - Energy Marketing & Trading and Other" above.
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Defined Benefits

PPL Energy Supply subsidiaries sponsor and participate in various qualified funded and non-qualified unfunded defined benefit pension plans.  A PPL Energy Supply subsidiary also sponsors an unfunded other postretirement benefit plan.  PPL Energy Supply records the liability and net periodic defined benefit costs of its plans and the allocated portion of those plans sponsored by PPL Services based on participation in those plans.  PPL Energy Supply subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI.  Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.  See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.

PPL Services and PPL Energy Supply make certain assumptions regarding the valuation of benefit obligations and the performance of plan assets.  When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle.  Annual net periodic defined benefit costs are recorded in current earnings based on estimated results.  Any differences between actual and estimated results are recorded in OCI.  These amounts in AOCI are amortized to income over future periods.  The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans.  The primary assumptions are:

·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  These projected returns reduce the net benefit costs PPL records currently.

·Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

·Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.

In selecting a discount rate for their U.S. defined benefit plans, PPL Services and PPL Energy Supply start with a cash flow analysis of the expected benefit payment stream for their plans.  The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds.  This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds.  Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.  At December 31, 2012, PPL Services decreased the discount rate for its U.S. pension plans from 5.07% to 4.22% and PPL Energy Supply decreased the discount rate for its pension plan from 5.12% to 4.25%.  PPL Services decreased the discount rate for its other postretirement benefit plan from 4.81% to 4.02% and PPL Energy Supply decreased the discount rate for its other postretirement benefit plan from 4.60% to 3.77%.

The expected long-term rates of return for PPL Services and PPL Energy Supply's U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class.  PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific asset allocation is also considered in developing a reasonable return assumption.  At December 31, 2012, PPL Services' and PPL Energy Supply's expected return on plan assets remained at 7.00% for their U.S. pension plans and increased from 5.70% to 5.75% for PPL Services' other postretirement benefit plan.

In selecting a rate of compensation increase, PPL Energy Supply considers past experience in light of movements in inflation rates.  At December 31, 2012, PPL Services and PPL Energy Supply's rate of compensation increase decreased from 4.00% to 3.95% for their U.S. plans.
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In selecting health care cost trend rates, PPL Services and PPL Energy Supply consider past performance and forecasts of health care costs.  At December 31, 2012, PPL Services' and PPL Energy Supply's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.

A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI.  While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI by a similar amount in the opposite direction.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.

At December 31, 2012, the defined benefit plans were recorded as follows.

Pension liabilities$ (295)
Other postretirement benefit liabilities (77)

The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL Services' and PPL Energy Supply's primary defined benefit plans.

   Increase (Decrease)
   Change in  Impact on defined   
Actuarial assumption  assumption  benefit liabilities  Impact on OCI
          
Discount Rate  (0.25)% $ 56  $ (56)
Rate of Compensation Increase  0.25%   9    (9)
Health Care Cost Trend Rate (a)  1.00%   1    (1)

(a)Only impacts other postretirement benefits.

In 2012, PPL Energy Supply was allocated and recognized net periodic defined benefit costs charged to operating expense of $44 million.  This amount represents a $10 million increase from 2011.

The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL's and PPL Energy Supply's primary defined benefit plans.

Actuarial assumption  Change in assumption  Impact on defined benefit costs
       
Discount Rate  (0.25)% $ 4 
Expected Return on Plan Assets  (0.25)%   3 
Rate of Compensation Increase  0.25%   2 

Asset Impairment (Excluding Investments)

Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable.  For these long-lived assets classified as held and used, such events or changes in circumstances are:

·a significant decrease in the market price of an asset;
·a significant adverse change in the manner in which an asset is being used or in its physical condition;
·a significant adverse change in legal factors or in the business climate;
·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
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For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value.  Management must make significant judgments to estimate future cash flows, including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets.  Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome.  If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives.  For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets.  That assessment is not revised based on events that occur after the balance sheet date.  Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.

In September 2012, PPL Energy Supply announced its intention, beginning in April 2015, to place the Corette coal-fired plant in Montana in long-term reserve status, suspending the plant's operation, due to expected market conditions and the costs to comply with MATS requirements.  The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million.  An impairment analysis was performed for this asset group in the third and fourth quarters of 2012 and it was determined to not be impaired.  It is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.

For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell.  If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell.  A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.

For determining fair value, quoted market prices in active markets are the best evidence.  However, when market prices are unavailable, the Registrant considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained.  Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available.  Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.

Goodwill is tested for impairment at the reporting unit level.  PPL Energy Supply's reporting unit has been determined to be at the operating segment level.  A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value.  Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.

Beginning in 2012, PPL Energy Supply may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test.  If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary.  However, the quantitative impairment test is required if PPL Energy Supply concludes it is more likely than not that the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.

When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, PPL Energy Supply identifies a potential impairment by comparing the estimated fair value of PPL Energy Supply (the goodwill reporting unit) with its carrying amount, including goodwill, on the measurement date.  If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired.  If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.

The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination.  That is, the estimated fair value is allocated to all of PPL Energy Supply's assets and liabilities as if PPL Energy Supply had been acquired in a business combination and the estimated fair value of PPL Energy Supply was the price paid.  The excess of the estimated fair value of PPL Energy Supply over the amounts assigned to its assets and liabilities is the implied fair value of goodwill.  The implied fair value of PPL Energy Supply's goodwill is then compared with the carrying amount of that goodwill.  If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess.  The loss recognized cannot exceed the carrying amount of PPL Energy Supply's goodwill.
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PPL Energy Supply elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 and no impairment was recognized.  Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of PPL Energy Supply.  Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.

Loss Accruals

Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes.  For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated.  Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur."  The accrual of contingencies that might result in gains is not recorded unless recovery is assured.  Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.

The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient.  All three of these aspects require significant judgment by management.  Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.

No new significant loss accruals were recorded in 2012.  

Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual.  Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred.

When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable.  The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated.  The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:

·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable.

Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate.  This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.

See Note 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.

Asset Retirement Obligations

PPL Energy Supply is required to recognize a liability for legal obligations associated with the retirement of long-lived assets.  The initial obligation should be measured at its estimated fair value.  A conditional ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated.  An equivalent amount should be recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset.  Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the statement of income, for changes in the obligation due to the passage of time.  See Note 21 to the Financial Statements for further discussion of AROs.
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In determining AROs, management must make significant judgments and estimates to calculate fair value.  Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred.  Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements.  Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO.  Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset.

At December 31, 2012, AROs totaling $375 million were recorded on the Balance Sheet, of which $10 million is included in "Other current liabilities."  Of the total amount, $316 million, or 84%, relates to the nuclear decommissioning ARO.  The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates.  A variance in any of these inputs could have a significant impact on the ARO liabilities.

The following table reflects the sensitivities related to the nuclear decommissioning ARO liability associated with a change in these assumptions as of December 31, 2012.  There is no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of changing the assumptions.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.

  Change in Impact on
  Assumption ARO Liability
       
Retirement Cost  10% $32
Discount Rate  (0.25)%  28
Inflation Rate  0.25%  32

Income Taxes

Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position.  Tax positions are evaluated following a two-step process.  The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained.  This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position.  The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion.  The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%.  Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date.  Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured.  The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.

At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $1 million or decrease by up to $30 million.  This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the timing and utilization of tax credits and the related impact on alternative minimum tax, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
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The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment.  Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.  Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset.  Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies.  Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position.  Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances.  The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.  See Note 5 to the Financial Statements for income tax disclosures.

Other Information

PPL's Audit Committee has approved the independent auditor to provide audit, audit-related and tax services permitted by Sarbanes-Oxley and SEC rules.  The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.

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PPL ELECTRIC UTILITIES CORPORATION AND SUBSIDIARIES

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations


The information provided in this Item 7 should be read in conjunction with PPL Electric's Consolidated Financial Statements and the accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

·  "Overview" provides a description of PPL Electric and its business strategy, a summary of Net Income Available to PPL and a discussion of certain events related to PPL Electric's results of operations and financial condition.

·  "Results of Operations" provides a summary of PPL Electric's earnings and a description of key factors expected to impact future earnings.  This section ends with explanations of significant changes in principal items on PPL Electric's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.

·  "Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL Electric's liquidity position and credit profile.  This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.

·  "Financial Condition - Risk Management" provides an explanation of PPL Electric's risk management programs relating to market and credit risk.

·  "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL Electric and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.

Overview

Introduction

PPL Electric is an electricity transmission and distribution service provider in eastern and central Pennsylvania with headquarters in Allentown, Pennsylvania.  PPL Electric is subject to regulation as a public utility by the PUC, and certain of its transmission activities are subject to the jurisdiction of FERC under the Federal Power Act.  PPL Electric delivers electricity in its Pennsylvania service area and provides electricity supply to retail customers in that territory as a PLR under the Customer Choice Act.

Business Strategy

PPL Electric's strategy and principal challenge is to own and operate its electricity delivery business at the most efficient cost while maintaining high quality customer service and reliability.  PPL Electric anticipates that it will have significant capital expenditure requirements for at least the next five years.  In order to manage financing costs and access to credit markets, a key objective for PPL Electric's business is to maintain a strong credit profile and strong liquidity position.

Timely recovery of costs to maintain and enhance the reliability of PPL Electric's delivery system including the replacement of aging distribution assets is required in order to maintain strong cash flows and a strong credit profile.  Traditionally, such cost recovery would be pursued through periodic base rate case proceedings with the PUC.  As such costs continue to increase, more frequent rate case proceedings may be required or an alternative rate-making process would need to be implemented in order to achieve more timely recovery.  See "Regulatory Matters - Pennsylvania Activities - Legislation - Regulatory Procedures and Mechanisms" in Note 6 to the Financial Statements for information on Pennsylvania's new alternative rate-making mechanism.

Transmission costs are recovered through a FERC Formula Rate mechanism which is updated annually for costs incurred and assets placed in service.  Accordingly, increased costs including for the replacement of aging transmission assets and the PJM-approved Regional Transmission Line Expansion Plan are recovered on a timely basis.


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Financial and Operational Developments

Net Income Available to PPL

Net Income Available to PPL for 2012, 2011 and 2010 was $132 million, $173 million and $115 million.  Earnings in 2012 decreased 24% from 2011 and earnings in 2011 increased 50% over 2010.

See "Results of Operations" below for further discussion and analysis of PPL Electric's earnings.

Redemption of Preference Stock

In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share.  The price paid for the redemption was the par value, without premium ($250 million in the aggregate).  At December 31, 2011, the preference stock was reflected on PPL Electric's Balance Sheet in "Preferred securities."

Storm Costs

During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits.  Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statements of Income.  PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income).  In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.

See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for information on $84 million of storm costs incurred in 2011.

Rate Case Proceeding

In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013.  In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million.  The approved rates became effective January 1, 2013.

Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order.  PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.

Regional Transmission Line Expansion Plan

Susquehanna-Roseland

In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid.  PJM determined that the line was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system.  PJM directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.

On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review.  On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation; and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint.  PPL Electric has intervened in the lawsuit.  The chosen route had previously been approved by the PUC and New Jersey Board of Public Utilities.
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On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.

Construction activities have begun on portions of the 101-mile route in Pennsylvania.  The line is expected to be in service before the peak summer demand period of 2015.  At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.

PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.

Northeast/Pocono

In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities).  The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project.  The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive.  The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit to the FERC in March 2013.  PPL Electric expects the project to be completed in 2017.  At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.

Legislation - Regulatory Procedures and Mechanisms

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC.  Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets.  In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for the implementation of Act 11.  Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DISC.  The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DISC.  In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC.  The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.

FERC Formula Rates

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization.  This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC.  At December 31, 2012 and December 31, 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and are included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets."  In May 2012, the FERC issued an order approving PPL Electric's request recover the deferred tax regulatory asset over a 34 year period beginning June 1, 2012.

Results of Operations

The following discussion provides a summary of PPL Electric's earnings and a description of factors that are expected to impact future earnings.  This section ends with "Statement of Income Analysis," which includes explanations of significant year-to-year changes in Pennsylvania Gross Delivery Margins by component and principal line items on PPL Electric's Statements of Income.

The utility business is influenced by seasonality in the weather.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  Revenue is generally higher during the first and third quarters of a year due to higher demand as a result of winter and summer periods.  On the other hand, revenue tends to be lower during the second and fourth quarters due to lower demand as a result of milder weather.

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Earnings         
           
Net Income Available to PPL was:
           
   2012  2011  2010 
           
Net Income Available to PPL $ 132  $ 173  $ 115 

The changes in the components of Net Income Available to PPL between these periods were due to the following factors which reflect reclassifications for items included in gross delivery margins.
  2012 vs. 2011 2011 vs. 2010
       
Pennsylvania Gross Delivery Margins $ 19  $ 66 
Other operation and maintenance   (50)   4 
Depreciation   (14)   (10)
Taxes, other than income   (9)   4 
Other   1    1 
Income Taxes      (11)
Distributions on Preferred Securities   12    4 
Total $ (41) $ 58 

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins.

·  Higher other operation and maintenance for 2012 compared with 2011, primarily due to $17 million in higher payroll-related costs due to less project costs being capitalized in 2012, higher support group costs of $11 million and $10 million for increased vegetation management.

·  Higher depreciation for 2012 compared with 2011 and 2011 compared with 2010 primarily due to PP&E additions.

·  Higher taxes, other than income for 2012 primarily due to a $10 million tax provision related to gross receipts tax.

·Income taxes were flat in 2012 compared with 2011 primarily due to the $22 million impact of lower 2012 pre-tax income primarily offset by $9 million of depreciation not normalized and $9 million of income tax return adjustments, largely related to changes in flow-through regulated tax depreciation.

Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher 2011 pre-tax income, partially offset by a $14 million tax benefit related to changes in flow-through regulated tax depreciation.

·Lower distributions on preferred securities in 2012 compared to 2011 due to the preference stock redemption in June 2012.

2013 Outlook

PPL Electric projects higher earnings in 2013 compared with 2012, due to higher distribution revenues from a distribution base rate increase effective January 1, 2013, and higher transmission margins, partially offset by higher depreciation.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
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Statement of Income Analysis --

Pennsylvania Gross Delivery Margins

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Pennsylvania Gross Delivery Margins."  "Pennsylvania Gross Delivery Margins" is a single financial performance measure of PPL Electric's Pennsylvania regulated electric delivery operations, which includes transmission and distribution activities.  In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings.  Costs associated with these mechanisms are recorded in "Energy purchases," "Energy purchases from affiliate," "Other operation and maintenance," which is primarily Act 129 costs, and "Taxes, other than income" which is primarily gross receipts tax.  As a result, this measure represents the net revenues from PPL Electric's Pennsylvania regulated electric delivery operations.  This measure is not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance.  Other companies may use different measures to analyze and to report on the results of their operations.  PPL Electric believes that "Pennsylvania Gross Delivery Margins" provides another criterion to make investment decisions.  This performance measure is used, in conjunction with other information, internally by senior management to manage PPL Electric's operations and analyze actual results to budget.
Reconciliation of Non-GAAP Financial Measures

The following tables reconcile "Operating Income" to "Pennsylvania Gross Delivery Margins" as defined by PPL Electric for the period ended December 31.

      2012  2011 
      PA Gross       PA Gross      
      Delivery    Operating Delivery     Operating
      Margins Other (a) Income (b) Margins Other (a) Income (b)
                   
Operating Revenues                    
 Retail electric $ 1,760      $ 1,760  $ 1,881      $ 1,881 
 Electric revenue from affiliate   3        3    11        11 
   Total Operating Revenues   1,763        1,763    1,892        1,892 
                         
Operating Expenses                    
 Energy purchases   550        550    738        738 
 Energy purchases from affiliate   78        78    26        26 
 Other operation and                    
  maintenance   104  $ 472     576    108  $ 422     530 
 Depreciation      160     160       146     146 
 Taxes, other than income   91    14     105    99    5     104 
   Total Operating Expenses   823    646     1,469    971    573     1,544 
Total $ 940  $ (646)  $ 294  $ 921  $ (573)  $ 348 

      2010   
      PA Gross              
      Delivery    Operating        
      Margins Other (a) Income (b)      
                   
Operating Revenues                    
 Retail electric $ 2,448      $ 2,448           
 Electric revenue from affiliate   7        7           
   Total Operating Revenues   2,455        2,455           
                         
Operating Expenses                    
 Energy purchases   1,075        1,075           
 Energy purchases from affiliate   320        320           
 Other operation and                    
  maintenance   76  $ 426     502           
 Amortization of recoverable                    
 Depreciation      136     136           
 Taxes, other than income   129    9     138           
   Total Operating Expenses   1,600    571     2,171           
Total $ 855  $ (571)  $ 284           

(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.

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Changes in Non-GAAP Financial Measures

The following table shows PPL Electric's non-GAAP financial measure, "Pennsylvania Gross Delivery Margins" for the periods ended December 31, as well as the change between periods.  The factors that gave rise to the change are described below the table.

   2012  2011  Change 2011  2010  Change
                    
PA Gross Delivery Margins by Component                  
 Distribution $ 730  $ 741  $ (11) $ 741  $ 679  $ 62 
 Transmission   210    180    30    180    176    4 
 Total $ 940  $ 921  $ 19  $ 921  $ 855  $ 66 

Distribution

Margins decreased in 2012 compared with 2011, primarily due to a $14 million unfavorable effect of mild weather early in 2012 and lower revenue applicable to certain energy-related costs of $3 million due to fewer PLR customers in 2012, partially offset by a $7 million charge recorded in 2011 to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC.

Margins increased in 2011 compared with 2010, largely due to the PPL Electric distribution rate case which increased rates by approximately 1.6% effective January 1, 2011, resulting in improved residential distribution margins of $68 million.  Additionally, residential volume variances increased margins by an additional $4 million in 2011, compared with 2010, offset by unfavorable weather of $3 million for residential customers in 2011 compared with 2010.  Lastly, lower demand charges and increased efficiency as a result of Act 129 programs resulted in a $5 million decrease in margins for commercial and industrial customers.

Transmission

Margins increased in 2012 compared with 2011, primarily due to increased investment in plant and the recovery of additional costs through the FERC formula-based rates.

Other Operation and Maintenance

The increase (decrease) in other operation and maintenance was due to:

  2012 vs. 2011 2011 vs. 2010
       
Act 129 costs incurred (a) $ (6) $ 26 
Vegetation management (b)   10    (8)
Payroll-related costs (c)   17    4 
Allocation of certain corporate support group costs   11    3 
PUC-reportable storm costs, net of insurance recovery   7    
Uncollectible accounts   1    7 
Other   6    (4)
Total $ 46  $ 28 

(a)Relates to costs associated with PPL Electric's PUC-approved energy efficiency and conservation plan.  These costs are recovered in customer rates.  There were initially 15 Act 129 programs which began in 2010 and continued to ramp up in 2011.  Some of the energy efficiency programs were reduced or closed in 2012 resulting in lower operation and maintenance expense.
(b)PPL Electric incurred more expense in 2010 and 2012 compared to 2011 due to increased vegetation management activities related to transmission lines to comply with federal reliability requirements as well as increased vegetation management for the distribution system in 2012 in an effort to maintain and increase system reliability.
(c)Higher payroll costs of $17 million in 2012 compared to 2011 due to less project costs being capitalized.

Taxes, Other Than Income

Taxes, other than income increased by $1 million in 2012 compared with 2011.  The increase was primarily a result of the net effect of the fully amortized PURTA refund to customers of $10 million in 2011, partially offset by a decrease in gross receipts tax of $7 million in 2012.
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Taxes, other than income decreased by $34 million in 2011 compared with 2010.  This decrease was primarily due to $21 million of lower Pennsylvania gross receipts tax expense on lower retail electricity revenue as customers continue to select alternative suppliers in 2011.  The decrease was also impacted by the amortization of a PURTA refund of $10 million in 2011.  Pennsylvania gross receipts tax and the PURTA refund are included in "Pennsylvania Gross Delivery Margins."

Depreciation

Depreciation increased by $14 million in 2012 compared with 2011 and by $10 million in 2011 compared with 2010, primarily due to PP&E additions as part of ongoing investments to replace aging infrastructure.

Financing Costs

The increase (decrease) in financing costs, which includes "Interest Expense", "Interest Expense with Affiliate" and "Distributions on Preferred Securities," was due to:

  2012 vs. 2011 2011 vs. 2010
       
Long-term debt interest expense $ 1  $ (3)
Distributions on preferred securities (a)   (12)   (4)
Amortization of debt issuance costs (b)   1    5 
Other   (1)   (3)
Total $ (11) $ (5)

(a)Decreases for both periods are due to the redemption of preference stock in 2012 and preferred stock in 2010.
(b)The increase in 2011 compared with 2010 was primarily due to amortization of loss on reacquired debt associated with the redemption of senior    secured bonds in 2011.

Income Taxes

The increase (decrease) in income taxes was due to:

  2012 vs. 2011 2011 vs. 2010
       
Higher (lower) pre-tax book income $ (22) $ 26 
Federal and state tax reserve adjustments (a)   1    3 
Federal and state tax return adjustments (b)   11    (3)
Depreciation not normalized (c)   9    (14)
Other   1    (1)
Total $  $ 11 

(a)In July 2010, the U.S. Tax Court ruled in PPL Electric's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years.  As a result, PPL Electric recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes during 2010.

(b)PPL Electric changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year.  In August, 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets.  The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes.  PPL Electric adopted the safe harbor method with the filing of its 2011 federal income tax return and recorded a $5 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.

During 2011, PPL Electric recorded a $5 million federal and state income tax benefit as a result of filing its 2010 federal and state income tax returns.  The tax benefit primarily related to the flow-through impact of Pennsylvania regulated 100% bonus tax depreciation.
(c)During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes.  The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes.  The 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.  The federal provision for 100% bonus depreciation generally applies to property placed in service before January 1, 2012.  The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer that one year and has a tax life of at least ten years.  The PPL Electric's tax deduction for 100% bonus depreciation was significantly lower in 2012 than in 2011.

See Note 5 to the Financial Statements for additional information on income taxes.
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Financial Condition

Liquidity and Capital Resources

PPL Electric continues to focus on maintaining a strong credit profile and liquidity position.  PPL Electric expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances.  Additionally, subject to market conditions, PPL Electric currently plans to issue long-term debt in 2013.

PPL Electric's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:

·unusual or extreme weather that may damage PPL Electric's transmission and distribution facilities or affect energy sales to customers;
·the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·any adverse outcome of legal proceedings and investigations with respect to PPL Electric's current and past business activities;
·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·a downgrade in PPL Electric's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt.

See "Item 1A. Risk Factors" for further discussion of risks and uncertainties that could affect PPL Electric's cash flows.

At December 31, PPL Electric had the following:

  2012  2011  2010 
          
Cash and cash equivalents $ 140  $ 320  $ 204 

The changes in PPL Electric's cash and cash equivalents position resulted from:

  2012  2011  2010 
          
Net cash provided by (used in) operating activities $ 389  $ 420  $ 212 
Net cash provided by (used in) investing activities   (613)   (477)   (403)
Net cash provided by (used in) financing activities   44    173    (90)
Net Increase (Decrease) in Cash and Cash Equivalents $ (180) $ 116  $ (281)

Operating Activities

Net cash provided by operating activities decreased by 7%, or $31 million, in 2012 compared with 2011, primarily due to changes in working capital of $82 million partially offset by a decrease in defined benefit plan contributions of $54 million.  Changes in working capital included $108 million from regulatory assets and liabilities, net and $56 million from prepayments, partially offset by $95 million from accounts payable.

Net cash provided by operating activities increased by 98%, or $208 million, in 2011 compared with 2010, primarily due to changes in working capital of $322 million (including lower gross receipts tax payments, a federal income tax refund and changes in over/under collections of the generation supply and transmission service charges).  These changes were partially offset by an increase in defined benefit plan contributions of $58 million and $25 million related to storm costs incurred in 2011 and recorded as a long-term regulatory asset.

Investing Activities

The primary use of cash in investing activities is capital expenditures.  See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.

Net cash used in investing activities was $613 million in 2012 compared with $477 million in 2011.  The change from 2011 to 2012 primarily reflects an increase of $143 million in capital expenditures in 2012.

Net cash used in investing activities was $477 million in 2011 compared with $403 million in 2010.  The change from 2010 to 2011 primarily reflects an increase of $80 million in capital expenditures in 2011.

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Financing Activities

Net cash provided by financing activities was $44 million in 2012 compared with $173 million in 2011.  The change from 2011 to 2012 primarily reflects the $250 million preference stock redemption in 2012, offset by a $62 million increase in net debt issuances and a $50 million increase in contributions from PPL.

Net cash provided by financing activities was $173 million in 2011 compared with net cash used in financing activities of $90 million in 2010.  The change from 2010 to 2011 primarily reflects $187 million of net debt issuances in 2011 and $54 million of preferred stock redemptions in 2010.

PPL Electric's debt and equity financing activity in 2012 was:

    Issuance  Retirements
        
Preference Stock    $ (250)
First Mortgage Bonds, net of a discount or underwriting fees $  249    
 Total $ 249  $ (250)
Net decrease    $ (1)

See Note 7 to the Financial Statements for more detailed information regarding PPL Electric's financing activities in 2012.

Forecasted Sources of Cash

PPL Electric expects to continue to have sufficient sources of liquidity available in the near term, including cash flows from operations, credit facilities, commercial paper issuances and the issuance of long-term debt.

Credit Facilities

At December 31, 2012, PPL Electric's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:

         Letters of   
         Credit Issued   
       and  
   Committed   Commercial Unused
   Capacity Borrowed Paper Backstop Capacity
          
Syndicated Credit Facility (a) $ 300     $ 1  $ 299 
Asset-backed Credit Facility (b)   100      n/a   100 
Total PPL Electric Credit Facilities $ 400     $ 1  $ 399 

(a)PPL Electric's Syndicated Credit Facility contains a financial covenant requiring PPL Electric's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility, and other customary covenants.

The commitments under this credit facility are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 5% of the total committed capacity.
(b)PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis.  The subsidiary pledges these assets to secure loans of up to an aggregate of $100 million from a commercial paper conduit sponsored by a financial institution.  At December 31, 2012, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under this facility was $100 million.

In addition to the financial covenants noted above, the credit agreements governing the credit facilities contain financial and various other covenants.  Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements.  PPL Electric monitors compliance with the covenants on a regular basis.  At December 31, 2012, PPL Electric was in compliance with these covenants.  At this time, PPL Electric believes that these covenants and other borrowing conditions will not limit access to these funding sources.

See Note 7 to the Financial Statements for further discussion of PPL Electric's credit facilities.

Commercial Paper

PPL Electric maintains a $300 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are currently supported by PPL Electric's Syndicated Credit Facility.  PPL Electric had no commercial paper outstanding at December 31, 2012.

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Contributions from PPL

From time to time PPL may make capital contributions to PPL Electric.  PPL Electric may use these contributions for general corporate purposes.

Long-term Debt Securities

PPL Electric currently plans to incur, subject to market conditions, up to $400 million of long-term indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.

The Economic Stimulus Package

In April 2010, PPL Electric entered into an agreement with the DOE, in which the agency is to provide funding for one-half of a $38 million smart grid project.  The project included the deployment of smart grid technology to strengthen reliability, save energy and improve electric service for 60,000 Harrisburg, Pennsylvania area customers.  It also provides benefits beyond the Harrisburg region, helping to speed power restoration across PPL Electric's 29-county service territory.  Work on the grant project is complete as of December 31, 2012.

Forecasted Uses of Cash

In addition to expenditures required for normal operating activities, such as purchased power, payroll, and taxes, PPL Electric currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of its debt securities.

Capital Expenditures

The table below shows PPL Electric's current capital expenditure projections for the years 2013 through 2017.
    Projected
    2013  2014  2015  2016  2017 
Construction expenditures (a) (b)               
 Distribution facilities $ 352  $ 321  $ 309  $ 294  $ 297 
 Transmission facilities   616    532    399    357    313 
 Total Capital Expenditures $ 968  $ 853  $ 708  $ 651  $ 610 

(a)Construction expenditures include AFUDC, which is expected to total approximately $54 million for the years 2013 through 2017.
(b)Includes expenditures for intangible assets.

PPL Electric's capital expenditure projections for the years 2013 through 2017 total approximately $3.8 billion.  Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.  The table includes projected costs for the asset optimization program focused on the replacement of aging transmission and distribution assets, and the PJM-approved regional transmission line expansion project.  See Note 8 to the Financial Statements for additional information.

PPL Electric plans to fund its capital expenditures in 2013 with cash from operations, equity contributions from PPL, and proceeds from the issuance of debt securities.

Contractual Obligations

PPL Electric has assumed various financial obligations and commitments in the ordinary course of conducting its business.  At December 31, 2012, the estimated contractual cash obligations of PPL Electric were:

    Total 2013  2014 - 2015 2016 - 2017 After 2017
                  
Long-term Debt (a) $ 1,974     $ 110     $ 1,864 
Interest on Long-term Debt (b)   1,711  $ 91    181  $ 171    1,268 
Purchase Obligations (c)   357    111    103    53    90 
Other Long-term Liabilities               
 Reflected on the Balance               
 Sheet under GAAP (d) (e)   88    88          
Total Contractual Cash Obligations $ 4,130  $ 290  $ 394  $ 224  $ 3,222 

(a)Reflects principal maturities only based on stated maturity dates.  PPL Electric does not have any capital or operating lease obligations.
(b)Assumes interest payments through stated maturity.

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(c)The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction.  Primarily includes PPL Electric's purchase obligations of electricity.  Open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented.
(d)The amounts represent contributions made or committed to be made for 2013 for PPL's U.S. pension plans.  See Note 13 to the Financial Statements for a discussion of expected contributions.
(e)At December 31, 2012, total unrecognized tax benefits of $26 million were excluded from this table as PPL Electric cannot reasonably estimate the amount and period of future payments.  See Note 5 to the Financial Statements for additional information.

Dividends

From time to time, as determined by its Board of Directors, PPL Electric pays dividends on its common stock to its parent, PPL.

Purchase or Redemption of Debt Securities

PPL Electric will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.

Rating Agency Actions

Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of PPL Electric.  Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.

A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues.  The credit ratings of PPL Electric are based on information provided by PPL Electric and other sources.  The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL Electric.  Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.  PPL Electric's credit ratings affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.

The following table sets forth PPL Electric's security credit ratings as of December 31, 2012.

Senior SecuredCommercial Paper
IssuerMoody'sS&PFitchMoody'sS&PFitch
PPL ElectricA3A-A-P-2A-2F-2

A downgrade in PPL Electric's credit ratings could result in higher borrowing costs and reduced access to capital markets.  PPL Electric does not have credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.

In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL Electric in 2012.

In August 2012, Fitch assigned a rating and outlook to PPL Electric's $250 million First Mortgage Bonds.

In August 2012, S&P and Moody's assigned a rating to PPL Electric's $250 million First Mortgage Bonds.

In December 2012, Fitch affirmed the issuer default rating, individual security rating and the outlook for PPL Electric.

Off-Balance Sheet Arrangements

PPL Electric has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party.  See Note 15 to the Financial Statements for a discussion of these agreements.
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Risk Management

Market Risk

Commodity Price and Volumetric Risk - PLR Contracts

PPL Electric is exposed to market price and volumetric risks from its obligation as PLR.  The PUC has approved a cost recovery mechanism that allows PPL Electric to pass through to customers the cost associated with fulfilling its PLR obligation.  This cost recovery mechanism substantially eliminates PPL Electric's exposure to market price risk.  PPL Electric also mitigates its exposure to volumetric risk by entering into full-requirement energy supply contracts for the majority of its PLR obligations.  These supply contracts transfer the volumetric risk associated with the PLR obligation to the energy suppliers.

Interest Rate Risk

PPL Electric issues debt to finance its operations, which exposes it to interest rate risk.  At December 31, 2012 and 2011, PPL Electric had no potential annual exposure to increased interest expense, based on its current debt portfolio.  PPL Electric is also exposed to changes in the fair value of its debt portfolio.  PPL Electric estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $93 million, compared with $94 million at December 31, 2011.

Credit Risk

Credit risk is the risk that PPL Electric would incur a loss as a result of nonperformance by counterparties of their contractual obligations.  PPL Electric requires that counterparties maintain specified credit ratings and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk.  However, PPL Electric has concentrations of suppliers, financial institutions and customers.  These concentrations may impact PPL Electric's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.

In 2009, the PUC approved PPL Electric's PLR procurement plan for the period January 2011 through May 2013.  To date, PPL Electric has conducted all of its planned competitive solicitations.

Under the standard Supply Master Agreement (the Agreement) for the competitive solicitation process, PPL Electric requires all suppliers to post collateral if their credit exposure exceeds an established credit limit.  In the event a supplier defaults on its obligation, PPL Electric would be required to seek replacement power in the market.  All incremental costs incurred by PPL Electric would be recoverable from customers in future rates.  At December 31, 2012, most of the successful bidders under all of the solicitations had an investment grade credit rating from S&P, and were not required to post collateral under the Agreement.  A small portion of bidders were required to post collateral, which totaled less than $1 million, under the Agreement.  There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.

See Notes 15, 16, 18 and 19 to the Financial Statements for additional information on the competitive solicitations, the Agreement, credit concentration and credit risk.

Related Party Transactions

PPL Electric is not aware of any material ownership interests or operating responsibility by senior management of PPL Electric in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL Electric.  See Note 16 to the Financial Statements for additional information on related party transactions.

Environmental Matters

Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL Electric's electricity transmission and distribution systems, as well as impacts on customers.  PPL Electric cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.

See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
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Competition

See "Item 1. Business - Segment Information - Pennsylvania Regulated Segment - Competition" for a discussion of competitive factors affecting PPL Electric.

New Accounting Guidance

See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.

Application of Critical Accounting Policies

Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies.  The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain.  Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements).  Senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.

Defined Benefits

PPL Electric participates in a qualified funded defined benefit pension plan, an unfunded non-qualified defined benefit plan and a funded other postretirement benefit plan, sponsored by other PPL subsidiaries and administered through PPL Services.  PPL Electric is allocated a significant portion of the liability and net periodic defined benefit pension and other postretirement costs of the plans sponsored by other PPL subsidiaries based on participation in those plans.  PPL Electric records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets.  Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.  See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.

PPL Services makes certain assumptions regarding the valuation of benefit obligations and the performance of plan assets.  When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle.  Annual net periodic defined benefit costs are recorded in current earnings based on estimated results.  Any differences between actual and estimated results are recorded in regulatory assets for amounts that are expected to be recovered through regulated customer rates.  The amount in regulatory assets is amortized to income over future periods.  The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans.  The primary assumptions are:

·
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  These projected returns reduce the net benefit costs PPL records currently.

·Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

·Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.

In selecting a discount rate for its U.S. defined benefit plans, PPL Services starts with a cash flow analysis of the expected benefit payment stream for its plans.  The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds.  This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds.  Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.  At December 31, 2012, PPL Services decreased the discount rate for its U.S. pension plans from 5.07% to 4.22% and decreased the discount rate for its other postretirement benefit plans from 4.81% to 4.02%.

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The expected long-term rates of return for PPL Services' U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class.  PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific asset allocation is also considered in developing a reasonable return assumption.  At December 31, 2012, PPL Services' expected return on plan assets remained at 7.00% for its U.S. pension plan and increased from 5.70% to 5.75% for its other postretirement benefit plan.

In selecting a rate of compensation increase, PPL Services considers past experience in light of movements in inflation rates.  At December 31, 2012, PPL Services' rate of compensation increase decreased from 4.00% to 3.95% for its U.S. plans.

In selecting health care cost trend rates for PPL Services' other postretirement benefit plans, PPL Services considers past performance and forecasts of health care costs.  At December 31, 2012, PPL Services' health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.

A variance in the assumptions listed above could have a significant impact on the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and the regulatory assets allocated to PPL Electric.  While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets by a similar amount in the opposite direction.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.

At December 31, 2012, the defined benefit plans were recorded as follows.

Pension liabilities$ (237)
Other postretirement benefit liabilities (61)

The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.

   Increase (Decrease)
   Change in Impact on defined Impact on
Actuarial assumption  assumption benefit liabilities regulatory assets
          
Discount Rate  (0.25)% $ 46  $ (46)
Rate of Compensation Increase  0.25%   7    (7)
Health Care Cost Trend Rate (a)  1.00%   1    (1)

(a)Only impacts other postretirement benefits.

In 2012, PPL Electric was allocated net periodic defined benefit costs charged to operating expense of $22 million.  This amount represents a $4 million increase compared with the charge recognized during 2011.

The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.

Actuarial assumption  Change in assumption  Impact on defined benefit costs
       
Discount Rate  (0.25)% $ 3 
Expected Return on Plan Assets  (0.25)%   3 
Rate of Compensation Increase  0.25%   1 

Loss Accruals

Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes.  For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated.  Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur."  The accrual of contingencies that might result in gains is not recorded unless recovery is assured.  Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
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The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient.  All three of these aspects require significant judgment by management.  Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.

No new significant loss accruals were recorded in 2012.

Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual.  Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred.

When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable.  The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated.  The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:

·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable.

Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate.  This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.

See Note 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.

Income Taxes

Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position.  Tax positions are evaluated following a two-step process.  The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained.  This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position.  The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion.  The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%.  Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date.  Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured.  The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.

At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $11 million or decrease by up to $25 million.  This change could result from the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
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The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment.  Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.  Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset.  Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies.  Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position.  See Note 5 to the Financial Statements for income tax disclosures.

Regulatory Assets and Liabilities

PPL Electric's electricity delivery business is subject to cost-based rate regulation.  As a result, the effects of regulatory actions are required to be reflected in the financial statements.  Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates.  Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.  In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation.  Based on this continual assessment, management believes the existing regulatory assets are probable of recovery.  This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future.  If future recovery of costs ceases to be probable, then asset write-offs would be required to be recognized in operating income.  Additionally, the regulatory agencies can provide flexibility in the manner and timing of depreciation of PP&E and amortization of regulatory assets.

At December 31, 2012, PPL Electric had regulatory assets of $853 million and regulatory liabilities of $60 million.  All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.

See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.

Revenue Recognition - Unbilled Revenue

Revenues related to the sale of energy are recorded when energy is delivered to customers.  Because customers are billed on cycles which vary based on the timing of the actual meter reads taken throughout the month, PPL Electric records estimates for unbilled revenues at the end of each reporting period.  Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters.  The unbilled estimate is based on daily load models, the meter read schedule, and actual weather data.  The unbilled accrual is based on estimated usage for each customer class, and the current rate schedule pricing.  At December 31, 2012 and 2011, PPL Electric had unbilled revenue of $110 million and $102 million.

Other Information

PPL's Audit Committee has approved the independent auditor to provide audit, audit-related and tax services permitted by Sarbanes-Oxley and SEC rules.  The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
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LG&E AND KU ENERGY LLC AND SUBSIDIARIES

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

The information provided in this Item 7 should be read in conjunction with LKE's Consolidated Financial Statements and the accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions, unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

·  "Overview" provides a description of LKE and its business strategy, a summary of Net Income and a discussion of certain events related to LKE's results of operations and financial condition.

·  "Results of Operations" provides a summary of LKE's earnings and a description of key factors expected to impact future earnings.  This section ends with explanations of significant changes in principal items on LKE's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.

·  "Financial Condition - Liquidity and Capital Resources" provides an analysis of LKE's liquidity position and credit profile.  This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.

·  "Financial Condition - Risk Management" provides an explanation of LKE's risk management programs relating to market and credit risk.

·  "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of LKE and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.

Overview

Introduction

LKE, headquartered in Louisville, Kentucky, is a holding company.  LKE became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010.  LKE has regulated utility operations through its subsidiaries, LG&E and KU, which constitute substantially all of LKE's assets.  LG&E and KU are engaged in the generation, transmission, distribution and sale of electric energy.  LG&E also engages in the distribution and sale of natural gas.  LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names.  KU also serves customers in Virginia under the Old Dominion Power name and in Tennessee under the KU name.  Refer to "Item 1. Business - Background" for a description of LKE's business.

Business Strategy

LKE's overall strategy is to provide reliable, safe, competitively priced energy to its customers and reasonable returns on regulated investments to its member.

A key objective for LKE is to maintain a strong credit profile through managing financing costs and access to credit markets.  LKE continually focuses on maintaining an appropriate capital structure and liquidity position.

Successor and Predecessor Financial Presentation

LKE's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor.  Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting.  Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE have not changed as a result of the acquisition.
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Financial and Operational Developments

Net Income

Net Income for 2012, 2011 and 2010 was $219 million, $265 million and $237 million.  Earnings in 2012 decreased 17% from 2011 and earnings in 2011 increased 12% from 2010.

See "Results of Operations" for a discussion and analysis of LKE's earnings.

Rate Case Proceedings

In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E.  In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement.  Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E.  The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU.  The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%.  On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement.  The new rates became effective on January 1, 2013.  In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

Equity Method Investment

KU owns 20% of the common stock of EEI.  Through a power marketer affiliated with its majority owner, EEI sells its output to third parties.  KU's investment in EEI is accounted for under the equity method of accounting.  KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.  During the fourth quarter of 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred.  Accordingly, KU recorded a $15 million impairment charge, net of taxes, related to this investment as of December 31, 2012, bringing the investment balance to zero.  The impairment charge is shown in the line "Other-Than-Temporary Impairments" on the Statement of Income for the year ended December 31, 2012.            

Registered Debt Exchange Offer by LKE

In June 2012, LKE completed an exchange of all its outstanding 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered under the Securities Act of 1933.  See Note 7 to the Financial Statements for additional information.

Commercial Paper

In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide an additional financing source to fund their short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by the issuer's credit facility.  At December 31, 2012, $125 million of commercial paper was outstanding.

Terminated Bluegrass CTs Acquisition

In September 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals.  In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs.  In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs.  In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns.  After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable.  In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
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Cane Run Unit 7 Construction

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7.  In May 2012, the KPSC issued an order approving the request.  A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings.  LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015.  The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.

In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring five older coal-fired electric generating units at the Cane Run and Green River plants, which have a combined summer capacity rating of 726 MW.  In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.

Future Capacity Needs

In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs.  As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.

Results of Operations

As previously noted, LKE's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010.  See "Overview - Successor and Predecessor Financial Presentation" for further information.

The utility business is affected by seasonal weather.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  Revenue and earnings are generally higher during the first and third quarters and lower during the second and fourth quarters due to weather.

The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:

Earnings

    Successor  Predecessor
        Two Months  Ten Months
    Year Ended Year Ended Ended  Ended
    December 31, December 31, December 31,  October 31,
    2012  2011  2010   2010 
                
 Net Income $ 219  $ 265  $ 47   $ 190 

The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.  See additional detail of these special items in the table below.

  2012 vs. 2011 2011 vs. 2010
     
Margins $ (8) $ 92 
Other operation and maintenance   (16)   (5)
Depreciation   (10)   (43)
Taxes, other than income   (9)   (14)
Other Income (Expense) - net   (14)   (13)
Interest Expense   (4)   29 
Income Taxes   31    (18)
Special items, after-tax   (16)   
Total $ (46) $ 28 

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins.

·
Higher other operation and maintenancein 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.

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·Higher depreciation in 2012 compared with 2011 due to PP&E additions.

Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.

·Higher taxes, other than income in 2011 compared with 2010 primarily due to a $9 million state coal tax credit that was applied to 2010 property taxes.  The remaining increase was due to higher assessments, primarily from significant property additions.

·Lower other income (expense) - net in 2012 compared with 2011 primarily due to losses from the EEI investment.

Lower other income (expense) - net in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset in 2010 for previously recorded losses on interest rate swaps.

·Lower interest expense in 2011 compared with 2010 due to lower interest rates and lower average long-term debt balances.  Lower interest rates contributed $17 million to the decrease in interest expense, as the interest rates on the first mortgage bonds were lower than the rates on the loans from E.ON AG affiliates, which were replaced.

·Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income.

Higher income taxes in 2011 compared with 2010 primarily due to higher pre-tax income.

The following after-tax gains (losses), which management considers special items, also impacted earnings.

  Income Statement Successor  Predecessor
  Line Item 2012  2011  2010   2010 
                
 Net operating loss carryforward and other tax-related adjustmentsIncome Taxes and Other O&M $ 4           
 Asset impairment, net of tax of $10 (a)Other-Than-Temporary Impairments   (15)          
 Discontinued operations adjustment, net of tax of $4 (b)Discontinued Operations   (5)          
 Energy-related economic activity, net of tax of $0, ($1), $1, $0 (c)Operating Revenues    $ 1  $ (1)    
 BREC terminated lease, net of tax of $0, $1, ($2), $1 (d)Discontinued Operations      (1)   2   $ (1)
Total  $ (16) $  $ 1   $ (1)

(a)KU recorded an impairment of its equity method investment in EEI.  See Note 18 to the Financial Statements for additional information.
(b)2012 includes an adjustment to an indemnification liability.
(c)Represents net unrealized gains (losses) on contracts that economically hedge anticipated cash flows.
(d)Represents costs associated with a terminated lease of WKE for the generating facilities of BREC.  See Note 9 to the Financial Statements for additional information.

2013 Outlook

Excluding special items, LKE projects higher earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --

Margins

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins."  Margins is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance.  Other companies may use different measures to analyze and to report on the results of their operations.  Margins is a single financial performance measure of LKE's electricity generation,
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transmission and distribution operations as well as its distribution and sale of natural gas.  In calculating this measure, fuel and energy purchases are deducted from revenues.  In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset.  These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives.  Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation."  As a result, this measure represents the net revenues from LKE's operations.  This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.

Reconciliation of Non-GAAP Financial Measures

The following tables reconcile "Operating Income" to "Margins" as defined by LKE for 2012, 2011 and 2010.

       2012 Successor    2011 Successor
           Operating        Operating
      Margins Other (a) Income (b)   Margins Other (a) Income (b)
                   
Operating Revenues $ 2,759     $ 2,759    $ 2,791  $ 2  $ 2,793 
Operating Expenses                    
 Fuel   872       872      866       866 
 Energy purchases   195       195      238       238 
 Other operation and maintenance   101  $ 677    778      90    661    751 
 Depreciation   51    295    346      49    285    334 
 Taxes, other than income      46    46         37    37 
   Total Operating Expenses   1,219    1,018    2,237      1,243    983    2,226 
Total $ 1,540  $ (1,018) $ 522    $ 1,548  $ (981) $ 567 

      Successor  Predecessor
      Two Months Ended December 31, 2010  Ten Months Ended October 31, 2010
           Operating        Operating
      Margins Other (a) Income (b)  Margins Other (a) Income (b)
                   
Operating Revenues $ 495  $ (1) $ 494   $ 2,214     $ 2,214 
Operating Expenses                   
 Fuel   138       138     723       723 
 Energy purchases   68       68     211       211 
 Other operation and maintenance   14    127    141     57  $ 529    586 
 Depreciation   7    42    49     35    200    235 
 Taxes, other than income      2    2        21    21 
   Total Operating Expenses   227    171    398     1,026    750    1,776 
Total $ 268  $ (172) $ 96   $ 1,188  $ (750) $ 438 

(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.

Changes in Non-GAAP Financial Measures

Margins decreased by $8 million for 2012 compared with 2011, primarily due to $6 million of lower wholesale margins resulting from lower market prices.  Retail margins were $2 million lower, as volumes were impacted by unseasonably mild weather during the first four months of 2012.  Total heating degree days decreased 11% compared to 2011, partially offset by a 6% increase in cooling degree days.

Margins increased by $92 million for 2011 compared with 2010.  New KPSC rates went into effect on August 1, 2010, contributing to an additional $112 million in operating revenue over the prior year.  Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
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Other Operation and Maintenance     
       
The increase (decrease) in other operation and maintenance was due to:
   
 2012 vs. 2011 2011 vs. 2010
       
Coal plant maintenance (a)$ 19  $4 
Distribution maintenance (b)  7   8 
Administrative and general (c)  (7)  (1)
Steam operation (d)  2   10 
Fuel for generation (e)    11 
Other generation maintenance    (4)
Other  6   (4)
Total$ 27  $ 24 

(a)Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages, as well as $5 million of increased maintenance at the Ghent plant on the scrubber system and primary fuel combustion system.
(b)Distribution maintenance costs increased in 2012 compared with 2011 primarily due to a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.

Distribution maintenance costs increased in 2011 compared with 2010 primarily due to $17 million of expenses related to amortization of storm restoration-related costs, a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work.  This increase was offset by a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
(c)Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost.
(d)Steam operation costs increased in 2011 compared with 2010 primarily due to higher variable costs as a result of TC2 commencing dispatch in 2011.
(e)Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period.

Depreciation

The increase (decrease) in depreciation was due to:

  2012 vs. 2011 2011 vs. 2010
       
TC2 (dispatch began in January 2011)   $ 32 
E.W. Brown sulfur dioxide scrubber equipment (placed in-service in June 2010)     8 
Other additions to PP&E$ 12    10 
Total$ 12  $ 50 

Taxes, Other Than Income

Taxes, other than income increased by $9 million in 2012 compared with 2011 due in part to a $4 million increase in property taxes resulting from property additions, higher assessed values and changes in property classifications to categories with higher tax rates.

Taxes, other than income increased by $14 million in 2011 compared with 2010 primarily due to a $9 million state coal tax credit that was applied to 2010 property taxes.  The remaining increase was due to higher assessments, primarily from significant property additions.

Other Income (Expense) - net

The increase (decrease) in other income (expense) - net was due to:

  2012 vs. 2011 2011 vs. 2010
       
Earnings (losses) from the EEI investment$ (9) $ (2)
Depreciation expense on TC2 joint-use assets held for future use     3 
Losses on interest rate swaps (a)     (19)
Other  (5)   5 
Total$ (14) $ (13)

(a)A regulatory asset was established in 2010 for previously recorded losses on interest rate swaps.
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Other-Than-Temporary Impairments

Other-than-temporary impairments increased by $25 million in 2012 compared with 2011 due to the $25 million pre-tax impairment of the EEI investment.  See Notes 1 and 18 to the Financial Statements for additional information.

Interest Expense

The increase (decrease) in interest expense was due to:

   2012 vs. 2011 2011 vs. 2010
        
Interest rates (a) $ (2) $ (17)
Long-term debt balances (b)   8    (15)
Other   (2)   3 
Total $ 4  $ (29)

(a)Interest expense decreased in 2011 compared with 2010 primarily due to lower interest rates on senior notes and first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates that were in place through October 2010.
(b)Interest expense increased in 2012 compared with 2011 due to the LKE $250 million senior notes that were issued in September 2011.

Interest expense decreased in 2011 compared with 2010 as the long-term debt balances were lower for the majority of 2011.  The debt balances increased in September 2011 due to the issuance of the LKE $250 million senior notes.

Income Taxes  
        
The increase (decrease) in income taxes was due to:
    
   2012 vs. 2011 2011 vs. 2010
        
Change in pre-tax income $ (34) $ 19 
Net operating loss carryforward adjustments (a)   (9)   
Other   (4)   
Total $ (47) $ 19 

(a)Adjustments to deferred taxes related to net operating loss carryforwards based on income tax return adjustments.

Income (Loss) from Discontinued Operations (net of income taxes)

Income (loss) from discontinued operations (net of income taxes) decreased by $5 million in 2012 compared with 2011 primarily related to an adjustment to the estimated liability for indemnifications related to the termination of the WKE lease in 2009.

Financial Condition

Liquidity and Capital Resources

LKE expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities, including commercial paper issuances. Additionally, subject to market conditions, subsidiaries of LKE currently plan to access capital markets in 2013.

LKE's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:

·changes in commodity prices that may increase the cost of producing or purchasing power or decrease the amount LKE receives from selling power;
·operational and credit risks associated with selling and marketing products in the wholesale power markets;
·unusual or extreme weather that may damage LKE's transmission and distribution facilities or affect energy sales to customers;
·reliance on transmission facilities that LKE does not own or control to deliver its electricity and natural gas;
·unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·costs of compliance with existing and new environmental laws;
·any adverse outcome of legal proceedings and investigations with respect to LKE's current and past business activities;

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·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·a downgrade in LKE's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt.

See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting LKE's cash flows.

At December 31, LKE had the following:

     
  2012  2011  2010 
          
Cash and cash equivalents $ 43  $ 59  $ 11 
Short-term investments (a)         163 
  $ 43  $ 59  $ 174 
          
Short-term debt (b) $ 125     $ 163 

(a)Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were purchased from the remarketing agent in 2008.  Such bonds were remarketed to unaffiliated investors in January 2011.  See Note 7 to the Financial Statements for additional information.
(b)Borrowings in 2012 were made under LG&E's and KU's commercial paper programs and borrowings in 2010 were made under LG&E's syndicated credit facility.  See Note 7 to the Financial Statements for additional information.

The changes in LKE's cash and cash equivalents position resulted from:

     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
              
Net cash provided by (used in) operating activities $ 747  $ 781  $ 26   $ 488 
Net cash provided by (used in) investing activities   (756)   (277)   (211)    (426)
Net cash provided by (used in) financing activities   (7)   (456)   167     (40)
Net Increase (Decrease) in Cash and Cash Equivalents $ (16) $ 48  $ (18)  $ 22 

Operating Activities

Net cash provided by operating activities decreased by 4%, or $34 million, in 2012 compared with 2011, primarily as a result of:
·Net income adjusted for non-cash items declined by $94 million, which included an $85 million reduction in deferred income taxes due primarily to the utilization of a capital loss carry forward in 2011.
·Working capital cash flow changes declined by $66 million driven primarily by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010 and more income tax receivables collected in 2011 than in 2012.
·These items were offset by $126 million increase in other operating cash flows driven by $100 million reduction in pension funding.
Net cash provided by operating activities increased by 52%, or $267 million, in 2011 compared with 2010, primarily as a result of:

·an increase in net income adjusted for non-cash effects of $178 million (deferred income taxes and investment tax credits of $101 million, depreciation of $50 million, amortization of regulatory assets of $24 million and other noncash items of $3 million, partially offset by unrealized (gains) losses on derivatives of $14 million, defined benefit plans - expense of $13 million and loss from discontinued operations - net of tax of $1 million);
·an increase in cash inflows related to income tax receivable of $79 million primarily due to net operating losses of $40 million recorded in 2010 and the payment of $40 million received by LKE for tax benefits in 2011;
·a net decrease in cash provided from accounts receivable and unbilled revenues of $75 million due to colder weather in December 2010 as compared with December 2009 and milder weather in December 2011 as compared with December 2010; and

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·a decrease in cash outflows of $28 million due to lower inventory levels in 2011 as compared with 2010 driven by $32 million for fuel inventory purchased in 2010 for TC2 that was not used until 2011 when TC2 began dispatch, $21 million due to lower coal burn as a result of unplanned outages at LG&E's Mill Creek plant and $6 million for decreases in gas storage volumes, partially offset by $22 million for KU's E.W. Brown and Ghent plants due primarily to increases in coal prices and $7 million for increases in coal in-transit; partially offset by
·an increase in discretionary defined benefit plan contributions of $105 million made in order to achieve LKE's long-term funding requirements.

Investing Activities

Net cash used in investing activities increased by 173%, or $479 million, in 2012 compared with 2011, primarily as a result of:

·
an increase in capital expenditures of $291 million, primarily due to coal combustion residuals projects at Ghent and E.W. Brown, environmental air projects at Mill Creek and Ghent, and construction of Cane Run Unit 7; and
·a decrease in the proceeds from the sale of other investments of $163 million in 2011.

Net cash used in investing activities decreased by 57%, or $360 million, in 2011 compared with 2010, as a result of:

·
proceeds from the sale of other investments of $163 million in 2011;
·
a decrease in capital expenditures of $122 million, primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011; and
·an increase from a change in notes receivable from affiliates of $107 million; partially offset by
·
proceeds from sales of discontinued operations of $21 million in 2010; and
·
a decrease in restricted cash of $11 million.

See "Forecasted Uses of Cash" for detail regarding capital expenditures for the years 2013 through 2017.

Financing Activities

Net cash used in financing activities was $7 million in 2012 compared with net cash used in financing activities of $456 million in 2011, primarily as a result of decrease in distributions to PPL.

In 2012, cash used in financing activities consisted of:

·
distributions to PPL of $155 million; partially offset by
·
the issuance of $125 million of short-term debt in the form of commercial paper; and
·
an increase in notes payable with affiliates of $25 million.

Net cash used in financing activities was $456 million in 2011 compared with net cash provided by financing activities of $127 million in 2010, primarily as a result of increased distributions to PPL and reduced contributions from PPL.

In 2011, cash used in financing activities consisted of:

·
distributions to PPL of $533 million, which includes $248 million using the proceeds of the long-term debt issuance noted below;
·a repayment on a revolving line of credit of $163 million;
·the payment of debt issuance and credit facility costs of $8 million; and
·the repayment of debt of $2 million; partially offset by
·the issuance of senior notes of $250 million.

In the two months of 2010 following PPL's acquisition of LKE, cash provided by financing activities of the Successor consisted of:

·the issuance of senior unsecured notes and first mortgage bonds of $2,890 million after discounts;
·the issuance of debt of $2,784 million to a PPL affiliate to repay debt due to E.ON AG affiliates upon the closing of PPL's acquisition of LKE;
·an equity contribution from PPL of $1,565 million; and
·a draw on a revolving line of credit of $163 million; partially offset by
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·the repayment of debt to E.ON AG affiliates of $4,319 million upon the closing of PPL's acquisition of LKE;
·the repayment of debt to a PPL affiliate of $2,784 million upon the issuance of senior unsecured notes and first mortgage bonds;
·distributions to PPL of $100 million; and
·the payment of debt issuance and credit facility costs of $32 million.

In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:

·the repayment of debt to an E.ON AG affiliate of $900 million;
·distributions to E.ON US Investments Corp. of $87 million; and
·a net decrease in notes payable with affiliates of $3 million; partially offset by
·the issuance of debt of $950 million to an E.ON AG affiliate.

See "Forecasted Sources of Cash" for a discussion of LKE's plans to issue debt securities, as well as a discussion of credit facility capacity available to LKE.  Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.

LKE's long-term debt securities activity through December 31, 2012 was:

    Debt
    Issuances Retirement
Non-cash Exchanges (a)      
 LKE Senior Unsecured Notes $ 250  $ (250)

(a)In June 2012, LKE completed an exchange of all of its outstanding 4.375% Senior Notes due 2021 issued in September 2011, in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered under the Securities Act of 1933.

See Note 7 to the Financial Statements for additional information about long-term debt securities.

Auction Rate Securities

At December 31, 2012, LG&E's and KU's tax-exempt revenue bonds that are in the form of auction rate securities and total $231 million continue to experience failed auctions.  Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures.  For the period ended December 31, 2012, the weighted-average rate on LG&E's and KU's auction rate bonds in total was 0.22%.

Forecasted Sources of Cash

LKE expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper programs, issuance of debt securities and operating cash flow.

Credit Facilities

At December 31, 2012, LKE's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:

      Borrowed /      
   Committed Commercial Letters of Unused
   Capacity Paper Issued Credit Issued Capacity
          
LKE Credit Facility with a subsidiary of PPL Energy Funding Corporation $ 300  $ 25     $ 275 
LG&E Credit Facility (a) (d)   500    55       445 
KU Credit Facilities (a) (b) (d)   598    70  $ 198    330 
 Total Credit Facilities (c) $ 1,398  $  150  $ 198  $ 1,050 

(a)In November 2012, LG&E and KU amended their syndicated credit facilities to extend the expiration dates to November 2017.  In addition, LG&E increased its credit facility's capacity to $500 million.
(b)In August 2012, the KU letter of credit facility agreement was amended and restated to allow for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.

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(c)The $1.098 billion of commitments under LG&E's and KU's domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 11% of the total committed capacity; however, the PPL affiliate provided a commitment of approximately 21% of the total facilities listed above. The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 70% for LG&E or KU, as calculated in accordance with the facility, and other customary covenants.
(d)Each company pays customary fees under their respective syndicated credit facilities, as well as KU's letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.

See Note 7 to the Financial Statements for further discussion of LKE's credit facilities.

Operating Leases

LKE and its subsidiaries also have available funding sources that are provided through operating leases.  LKE's subsidiaries lease office space, gas storage and certain equipment.  These leasing structures provide LKE additional operating and financing flexibility.  The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.

See Note 11 to the Financial Statements for further discussion of the operating leases.

Capital Contributions from PPL

From time to time PPL may make capital contributions to LKE.  LKE may use these contributions to fund capital expenditures, make capital contributions to its subsidiaries and for other general corporate purposes.

Long-term Debt Securities

LG&E and KU currently plan to issue, subject to market conditions, up to $350 million for LG&E and $300 million for KU, of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.

Forecasted Uses of Cash

In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, LKE currently expects to incur future cash outflows for capital expenditures, various contractual obligations, distributions to PPL and possibly the purchase or redemption of a portion of debt securities.

Capital Expenditures

The table below shows LKE's current capital expenditure projections for the years 2013 through 2017.

    Projected
    2013  2014  2015  2016  2017 
Capital expenditures (a)               
 Generating facilities $ 427  $ 251  $ 267  $ 476  $ 540 
 Distribution facilities   233    227    263    257    281 
 Transmission facilities   107    68    59    56    77 
 Environmental   655    722    513    292    107 
 Other   48    45    43    48    39 
  Total Capital Expenditures $ 1,470  $ 1,313  $ 1,145  $ 1,129  $ 1,044 

(a)LKE generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates.  The 2013 total excludes amounts included in accounts payable as of December 31, 2012.

LKE's capital expenditure projections for the years 2013 through 2017 total approximately $6.1 billion.  Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.  This table includes current estimates for LKE's environmental projects related to existing and proposed EPA compliance standards.  Actual costs may be significantly lower or higher depending on the final requirements and market conditions.  Environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.

LKE plans to fund its capital expenditures in 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
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Contractual Obligations

LKE has assumed various financial obligations and commitments in the ordinary course of conducting its business.  LKE is not liable for the debts of LG&E and KU, nor are LG&E and KU liable for the debts of one another.  Accordingly, creditors of LG&E and KU may not satisfy their debts from the assets of LKE absent a specific contractual undertaking by LKE or LG&E and KU to pay the creditors or as required by applicable law or regulation.  At December 31, 2012, the estimated contractual cash obligations of LKE were:

    Total 2013  2014 - 2015 2016 - 2017 After 2017
                  
Long-term Debt (a) $ 4,085     $ 900     $ 3,185 
Interest on Long-term Debt (b)   2,586  $ 139    274  $ 250    1,923 
Operating Leases (c)   90    15    27    14    34 
Coal and Natural Gas Purchase               
  Obligations (d)   2,558    789    1,176    501    92 
Unconditional Power Purchase               
  Obligations (e)   1,038    30    60    64    884 
Construction Obligations (f)   1,757    836    639    282    
Pension Benefit Plan Obligations (g) 153    153          
Other Obligations (h)   30    7    14    8    1 
Total Contractual Cash Obligations $ 12,297  $ 1,969  $ 3,090  $ 1,119  $ 6,119 

(a)Reflects principal maturities only based on stated maturity dates.  See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E and KU.  LKE has no capital lease obligations.
(b)Assumes interest payments through stated maturity.  The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)See Note 11 to the Financial Statements for additional information.
(d)Represents contracts to purchase coal, natural gas and natural gas transportation.  See Note 15 to the Financial Statements for additional information.
(e)Represents future minimum payments under OVEC power purchase agreements through June 2040.  See Note 15 to the Financial Statements for additional information.
(f)Represents construction commitments, including commitments for the Mill Creek and Ghent environmental air projects, Cane Run Unit 7, Ghent landfill and Ohio Falls refurbishment which are also reflected in the Capital Expenditures table presented above.
(g)Based on the current funded status of LKE's qualified pension plans, no cash contributions are required.  See Note 13 to the Financial Statements for a discussion of expected contributions.
(h)Represents other contractual obligations.

Dividends

From time to time, as determined by its Board of Directors, LKE pays dividends to the sole member, PPL.

As discussed in Note 7 to the Financial Statements, LG&E's and KU's ability to pay dividends is limited under a covenant in each of their revolving line of credit facilities.  This covenant restricts their debt to total capital ratio to not more than 70%.  See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for LKE subsidiaries.

Purchase or Redemption of Debt Securities

LKE will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.

Rating Agency Actions

Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of LKE and its subsidiaries.  Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.

A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues.  The credit ratings of LKE and its subsidiaries are based on information provided by LKE and other sources.  The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of LKE or its subsidiaries.  Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.  The credit ratings of LKE and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
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The following table sets forth LKE's and its subsidiaries' security credit ratings as of December 31, 2012.

Senior UnsecuredSenior SecuredCommercial Paper
IssuerMoody'sS&PFitchMoody'sS&PFitchMoody'sS&PFitch
LKEBaa2BBB-BBB+
LG&EAA2A-A+P-2A-2F-2
KUAA2A-A+P-2A-2F-2

In addition to the credit ratings noted above, the rating agencies took the following actions related to LKE and its subsidiaries:

In February 2012, Fitch assigned ratings to the two newly established commercial paper programs for LG&E and KU.

In March 2012, Moody's affirmed the following ratings:
·the long-term ratings of the First Mortgage Bonds for LG&E and KU;
·the issuer ratings for LG&E and KU; and
·the bank loan ratings for LG&E and KU.

Also in March 2012, Moody's and S&P each assigned short-term ratings to the two newly established commercial paper programs for LG&E and KU.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A, and 2007 Series B pollution control bonds.

In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.

In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlooks for LKE, LG&E and KU.

Ratings Triggers

LKE and its subsidiaries have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, commodity transportation and storage and interest rate instruments, which contain provisions requiring LKE and its subsidiaries to post additional collateral, or permitting the counterparty to terminate the contract, if LKE's or the subsidiaries' credit rating were to fall below investment grade.  See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012.  At December 31, 2012, if LKE's or its subsidiaries' credit ratings had been below investment grade, the maximum amount that LKE would have been required to post as additional collateral to counterparties was $78 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations, gas supply and interest rate contracts.

Off-Balance Sheet Arrangements

LKE has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party.  See Note 15 to the Financial Statements for a discussion of these agreements.

Risk Management

Market Risk

See Notes 1, 18 and 19 to the Financial Statements for information about LKE's risk management objectives, valuation techniques and accounting designations.
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The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions.  Actual future results may differ materially from those presented.  These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.

Commodity Price Risk (Non-trading)

LG&E's and KU's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers.  As a result, LG&E and KU are subject to commodity price risk for only a small portion of on-going business operations.  LKE sells excess economic generation to maximize the value of the physical assets at times when the assets are not required to serve LG&E's or KU's customers.  See Note 19 to the Financial Statements for additional disclosures.

The balance and change in net fair value of LKE's commodity derivative contracts for the periods ended December 31, 2012, 2011 and 2010 are shown in the table below.

     Gains (Losses)
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
                 
Fair value of contracts outstanding at the beginning of the period    $ (2)       
Contracts realized or otherwise settled during the period      (3)     $ 3 
Fair value of new contracts entered into during the period             (4)
Other changes in fair value (a)      5  $ (2)    1 
Fair value of contracts outstanding at the end of the period    $  $ (2)  $ 
(a)Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period.

Interest Rate Risk

LKE and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk.  LKE utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate.  Risk limits under LKE's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of LKE's debt portfolio due to changes in the absolute level of interest rates.

At December 31, 2012 and 2011, LKE's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.

LKE is also exposed to changes in the fair value of its debt portfolio.  LKE estimated that a 10% decrease in interest rates at December 31, 2012, would increase the fair value of its debt portfolio by $113 million compared with $125 million at December 31, 2011.

LKE had the following interest rate hedges outstanding at:  
                    
   December 31, 2012 December 31, 2011
         Effect of a       Effect of a
      Fair Value, 10% Adverse    Fair Value, 10% Adverse
   Exposure Net - Asset Movement Exposure Net - Asset Movement
   Hedged (Liability) (a) in Rates Hedged (Liability) (a) in Rates
Economic hedges                  
 Interest rate swaps (b) $179  $(58) $(3) $179  $(60) $(4)
Cash flow hedges                  
 Interest rate swaps (b)  300   14   (18)         

(a)Includes accrued interest.
(b)LKE utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments.  These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing.  While LKE is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic and cash flow hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities.  Sensitivities represent a 10% adverse movement in interest rates.  The positions outstanding at December 31, 2012 mature through 2043.
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Credit Risk

LKE is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations.  LKE maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds.  LKE is exposed to potential losses as a result of nonpayment by customers.  LKE maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers.  Allowances for doubtful accounts from wholesale and municipal customers and for miscellaneous receivables are based on specific identification by management.  Retail, wholesale and municipal customer accounts are written-off after four months of no payment activity.  Miscellaneous receivables are written-off as management determines them to be uncollectible.

Certain of LKE's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon LKE's credit ratings from each of the major credit rating agencies.  See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.

Related Party Transactions

LKE is not aware of any material ownership interest or operating responsibility by senior management of LKE, LG&E or KU in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with LKE.  See Note 16 to the Financial Statements for additional information on related party transactions.

Environmental Matters

Protection of the environment is a major priority for LKE and a significant element of its business activities.  Extensive federal, state and local environmental laws and regulations are applicable to LKE's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material.  In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies.  Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions.  Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for LKE's services.

Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to LKE's generation assets and electricity transmission and distribution systems, as well as impacts on customers.  In addition, changed weather patterns could potentially reduce annual rainfall in areas where LKE has hydro generating facilities or where river water is used to cool its fossil powered generators.  LKE cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.

See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.

New Accounting Guidance

See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.

Application of Critical Accounting Policies

Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies.  The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain.  Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements).  LKE's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
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Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers.  Because customers of LG&E's and KU's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, LKE records estimates for unbilled revenues at the end of each reporting period.  Such unbilled revenue amounts reflect estimates of the amount of electricity and gas delivered to customers since the date of the last reading of their meters.  The unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather, and where applicable, the impact of weather normalization or other regulatory provisions of rate structures.  In addition to the unbilled revenue accrual resulting from cycle billing, LKE makes additional accruals resulting from the timing of customer bills.  The accrual of unbilled revenues in this manner properly matches revenues and related costs.  At December 31, 2012 and 2011, LKE had unbilled revenue balances of $156 million and $146 million.
Defined Benefits

LKE and certain of its subsidiaries sponsor and participate in qualified funded and non-qualified unfunded defined benefit pension plans.  LKE also sponsors a funded other postretirement benefit plan.  These plans are applicable to the majority of the employees of LKE and its subsidiaries.  LKE records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or regulatory assets or liabilities.  Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.  See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.

Certain assumptions are made by LKE and certain of its subsidiaries regarding the valuation of benefit obligations and the performance of plan assets.  When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle.  Annual net periodic defined benefit costs are recorded in current earnings based on estimated results.  Any differences between actual and estimated results are recorded in OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates.  These amounts in regulatory assets and liabilities are amortized to income over future periods.  The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans.  The primary assumptions are:
·Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future.  The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  These projected returns reduce the net benefit costs LKE records currently.

·Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

·Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate for its defined benefit plans LKE starts with a cash flow analysis of the expected benefit payment stream for its plans.  The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds.  This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds.  Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.  At December 31, 2012, LKE decreased the discount rate for its pension plans from 5.08% to 4.24% and decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
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The expected long-term rates of return for LKE's defined benefit pension plans and defined other postretirement benefit plan have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class.  LKE management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific asset allocation is also considered in developing a reasonable return assumption.  At December 31, 2012, LKE's expected return on plan assets decreased from 7.25% to 7.10%.

In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates.  At December 31, 2012, LKE's rate of compensation increase remained at 4.00%.

In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs.  At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.

A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LKE.  While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LKE by a similar amount in the opposite direction.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.

At December 31, 2012, the defined benefit plans were recorded as follows:

Pension liabilities (a)$ 417 
Other postretirement benefit liabilities 141 

(a)Amount includes current and noncurrent portions.

The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on LKE's primary defined benefit plans.

  Increase (Decrease)
     Impact on    Impact on
  Change in defined benefit Impact on regulatory
Actuarial assumption assumption liabilities OCI assets
             
Discount Rate  (0.25)% $ 59  $ (22) $ 37 
Rate of Compensation Increase  0.25%   10    (6)   4 
Health Care Cost Trend Rate (a)  1%   5    (1)   4 

(a)Only impacts other postretirement benefits.

In 2012, LKE recognized net periodic defined benefit costs charged to operating expense of $40 million.  This amount represents an $11 million decrease from 2011.  This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $57 million, a reduction in the amortization of outstanding losses and lower interest cost.

The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on LKE's primary defined benefit plans.

Actuarial assumption   Change in assumption   Impact on defined benefit costs
       
Discount Rate  (0.25)% $ 4 
Expected Return on Plan Assets  (0.25)%   3 
Rate of Compensation Increase  0.25%   1 
Health Care Cost Trend Rate (a)  1%   

(a)Only impacts other postretirement benefits.
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Asset Impairment (Excluding Investments)
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable.  For these long-lived assets classified as held and used, such events or changes in circumstances are:
·a significant decrease in the market price of an asset;
·a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
·a significant adverse change in legal factors or in the business climate;
·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value.  Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets.  Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome.  If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives.  For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets.  That assessment is not revised based on events that occur after the balance sheet date.  Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.

For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell.  If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell.  A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence.  However, when market prices are unavailable, LKE considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained.  Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available.  Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
Goodwill is tested for impairment at the reporting unit level.  LKE's reporting units have been determined to be at the operating segment level.  A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value.  Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Beginning in 2012, LKE may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test.  If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary.  However, the quantitative impairment test is required if LKE concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment in step one, LKE identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying amount, including goodwill, on the measurement date.  If the estimated fair value of a reporting unit exceeds its carrying amount, goodwill is not considered impaired.  If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
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The second step of the quantitative test requires a calculation of the implied fair value of goodwill which is determined in the same manner as the amount of goodwill in a business combination.  That is, the estimated fair value of a reporting unit is allocated to all of the assets and liabilities of that reporting unit as if the reporting unit had been acquired in a business combination and the estimated fair value of the reporting unit was the price paid to acquire the reporting unit.  The excess of the estimated fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill.  The implied fair value of the reporting unit's goodwill is then compared with the carrying amount of that goodwill.  If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess.  The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
LKE elected to perform the two-step quantitative impairment test of goodwill for all of its reporting units in the fourth quarter of 2012 and no impairment was recognized.  Management used both discounted cash flows and market multiples, which required significant assumptions to estimate the fair value of each reporting unit.  Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Loss Accruals

Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes.  For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated.  Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured.  Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.

The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient.  All three of these aspects require significant judgment by management.  Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.

In 2012, the estimated liability for indemnifications related to the 2009 termination of the WKE lease was increased.

Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual.  Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred.  Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur."

When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable.  The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated.  The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved, LKE makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate.  This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.

See Note 15 to the Financial Statements for additional information.
Asset Retirement Obligations

LKE is required to recognize a liability for legal obligations associated with the retirement of long-lived assets.  The initial obligation is measured at its estimated fair value.  An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset.  Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Consolidated Statements of Income, for changes in the obligation due to the passage of time.  Since costs of removal are collected in rates, the accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact.  The regulatory asset created by the
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regulatory credit is relieved when the ARO has been settled.  An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated.  See Note 21 to the Financial Statements for related disclosures.

In determining AROs, management must make significant judgments and estimates to calculate fair value.  Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred.  Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements.  Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations.  Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.

At December 31, 2012, LKE had AROs comprised of current and noncurrent amounts, totaling $131 million recorded on the Balance Sheet.  Of the total amount, $90 million, or 69%, relates to LKE's ash ponds, landfills and natural gas mains.  The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates.  A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.

The following chart reflects the sensitivities related to LKE's ARO liabilities for ash ponds, landfills and natural gas mains at December 31, 2012:

  Change in Impact on
  Assumption ARO Liability
       
Retirement Cost  10% $ 11 
Discount Rate  (0.25)%   3 
Inflation Rate  0.25%   8 
Income Taxes

Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position.  Tax positions are evaluated following a two-step process.  The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained.  This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position.  The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion.  The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%.  Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date.  Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured.  The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.

At December 31, 2012, LKE's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is $1 million.  This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
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The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment.  Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.  Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset.  Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies.  Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position.  See Note 5 to the Financial Statements for related disclosures.
Regulatory Assets and Liabilities
LKE's subsidiaries, LG&E and KU, are cost-based rate-regulated utilities.  As a result, the effects of regulatory actions are required to be reflected in the financial statements.  Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates.  Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.  In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.  The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC, the KPSC, the VSCC and the TRA.

Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation.  Based on this continual assessment, management believes the existing regulatory assets are probable of recovery.  This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future.  If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income.  Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.

At December 31, 2012, LKE had regulatory assets of $649 million and regulatory liabilities of $1,011 million.  All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.

See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.

Other Information

PPL's Audit Committee has approved the independent auditor to provide audit, tax and other services permitted by Sarbanes-Oxley and SEC rules.  The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.  See "Item 14. Principal Accounting Fees and Services" for more information.

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LOUISVILLE GAS AND ELECTRIC COMPANY

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

The information provided in this Item 7 should be read in conjunction with LG&E's Financial Statements and the accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions, unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

·  "Overview" provides a description of LG&E and its business strategy, a summary of Net Income and a discussion of certain events related to LG&E's results of operations and financial condition.

·  "Results of Operations" provides a summary of LG&E's earnings and a description of key factors expected to impact future earnings.  This section ends with explanations of significant changes in principal items on LG&E's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.

·  "Financial Condition - Liquidity and Capital Resources" provides an analysis of LG&E's liquidity position and credit profile.  This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.

·  "Financial Condition - Risk Management" provides an explanation of LG&E's risk management programs relating to market and credit risk.

·  
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of LG&E and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.

Overview

Introduction

LG&E, headquartered in Louisville, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy and distribution and sale of natural gas in Kentucky.  LG&E and its affiliate, KU, are wholly owned subsidiaries of LKE.  LKE, a holding company, became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010.  Following the acquisition, both LG&E and KU continue operating as subsidiaries of LKE, which is now an intermediary holding company in PPL's group of companies.  Refer to "Item 1. Business - Background" for a description of LG&E's business.

Business Strategy

LG&E's overall strategy is to provide reliable, safe, competitively priced energy to its customers and reasonable returns on regulated investments to its shareowner.

A key objective for LG&E is to maintain a strong credit profile through managing financing costs and access to credit markets.  LG&E continually focuses on maintaining an appropriate capital structure and liquidity position.

Successor and Predecessor Financial Presentation

LG&E's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor.  Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting.  Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LG&E have not changed as a result of the acquisition.
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Financial and Operational Developments

Net Income

Net Income for 2012, 2011 and 2010 was $123 million, $124 million and $128 million.  Earnings in 2012 decreased 1% from 2011 and earnings in 2011 decreased 3% from 2010.

See "Results of Operations" for a discussion and analysis of LG&E's earnings.

Rate Case Proceedings

In June 2012, LG&E filed a request with the KPSC for an increase in annual base electric rates of approximately $62 million and an increase in annual base gas rates of approximately $17 million.  In November 2012, LG&E along with all of the parties filed a unanimous settlement agreement.  Among other things, the settlement provided for increases in annual base electric rates of $34 million and an increase in annual base gas rates of $15 million.  The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million.  The settlement agreement included an authorized return on equity of 10.25%.  On December 20, 2012, the KPSC issued an order approving the provisions in the settlement agreement.  The new rates became effective on January 1, 2013.  In addition to the increased base rates, the KPSC approved a gas line tracker mechanism to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.

Commercial Paper

In February 2012, LG&E established a commercial paper program for up to $250 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by LG&E's Syndicated Credit Facility.  At December 31, 2012, LG&E had $55 million of commercial paper outstanding.

Terminated Bluegrass CTs Acquisition

In September 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals.  In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs.  In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs.  In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns.  After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable.  In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.

Cane Run Unit 7 Construction

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7.  In May 2012, the KPSC issued an order approving the request.  LG&E will own a 22% undivided interest and KU will own a 78% undivided interest in the new generating unit.  A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings.  LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015.  The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.

In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E anticipates retiring three older coal-fired electric generating units at the Cane Run plant, which have a combined summer capacity rating of 563 MW.
Future Capacity Needs

In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs.  As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
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Results of Operations

As previously noted, LG&E's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010.  See "Overview - Successor and Predecessor Financial Presentation" for further information.

The utility business is affected by seasonal weather.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  Revenue and earnings are generally higher during the first and third quarters and lower during the second and fourth quarters due to weather.

The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:

Earnings

    Successor  Predecessor
        Two Months  Ten Months
    Year Ended Year Ended Ended  Ended
    December 31, December 31, December 31,  October 31,
    2012  2011  2010   2010 
                
 Net Income $ 123  $ 124  $ 19   $ 109 

The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.

  2012 vs. 2011 2011 vs. 2010
     
Margins $ 3  $ 39 
Other operation and maintenance   3    (10)
Depreciation   (4)   (13)
Taxes, other than income   (5)   (5)
Other Income (Expense) - net   (1)   (16)
Other   4    (1)
Special items, after-tax   (1)   2 
Total $ (1) $ (4)

The net unrealized gains (losses) on contracts that economically hedge anticipated cash flows are considered special items by management.  There were no unrealized gains (losses) in 2012.

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins.

·Higher other operation and maintenance in 2011 compared with 2010 primarily due to higher distribution maintenance costs of $8 million due to amortization of storm restoration related costs and a hazardous tree removal project initiated in August 2010.

·Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.

·Lower other income (expense) - net in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset in 2010 for previously recorded losses on interest rate swaps.

2013 Outlook

Excluding special items, LG&E projects higher earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
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Statement of Income Analysis --

Margins

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins."  Margins is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance.  Other companies may use different measures to analyze and to report on the results of their operations.  Margins is a single financial performance measure of LG&E's electricity generation, transmission and distribution operations as well as its distribution and sale of natural gas.  In calculating this measure, fuel and energy purchases are deducted from revenues.  In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset.  These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives.  Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation."  As a result, this measure represents the net revenues from LG&E's operations.  This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.

Reconciliation of Non-GAAP Financial Measures

The following tables reconcile "Operating Income" to "Margins" as defined by LG&E for 2012, 2011 and 2010.

      2012 Successor   2011 Successor
           Operating        Operating
      Margins Other (a) Income (b)   Margins Other (a) Income (b)
                   
Operating Revenues $ 1,324     $ 1,324    $ 1,363  $ 1  $ 1,364 
Operating Expenses                    
 Fuel   374       374      350       350 
 Energy purchases   175       175      245       245 
 Other operation and maintenance   45  $ 318    363      42    321    363 
 Depreciation   3    149    152      2    145    147 
 Taxes, other than income      23    23         18    18 
   Total Operating Expenses   597    490    1,087      639    484    1,123 
Total $ 727  $ (490) $ 237    $ 724  $ (483) $ 241 

      Successor  Predecessor
      Two Months Ended December 31, 2010  Ten Months Ended October 31, 2010
           Operating        Operating
      Margins Other (a) Income (b)  Margins Other (a) Income (b)
                   
Operating Revenues $ 255  $ (1) $ 254   $ 1,057     $ 1,057 
Operating Expenses                   
 Fuel   60       60     306       306 
 Energy purchases   63       63     155       155 
 Other operation and maintenance   9    58    67     28  $ 253    281 
 Depreciation      23    23     6    109    115 
 Taxes, other than income      1    1        12    12 
   Total Operating Expenses   132    82    214     495    374    869 
Total $ 123  $ (83) $ 40   $ 562  $ (374) $ 188 

(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.

Changes in Non-GAAP Financial Measures

Margins increased by $3 million for 2012 compared with 2011, primarily due to $9 million of higher retail margins as a result of new environmental investments.  This increase was partially offset by lower wholesale margins of $6 million as volumes were impacted by lower market prices.  Retail volumes were consistent with the prior year as increased industrial sales offset declines associated with unseasonably mild weather during the first four months of 2012.  Total heating degree days decreased 13% compared to 2011, partially offset by a 7% increase in cooling degree days.

Margins increased by $39 million for 2011 compared with 2010.  New KPSC rates went into effect on August 1, 2010, contributing to an additional $48 million in operating revenue over the prior year.  Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
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Other Operation and Maintenance     
       
The increase (decrease) in other operation and maintenance was due to:
   
  2012 vs. 2011 2011 vs. 2010
       
Administrative and general (a)$ (5) $ 4 
Distribution maintenance (b)  (1)   8 
Fuel for generation (c)     5 
Coal plant maintenance (d)  2    (5)
Other  4    3 
Total$  $ 15 

(a)Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost.
(b)Distribution maintenance costs increased in 2011 compared with 2010 primarily due to amortization of storm restoration-related costs, a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work.
(c)Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period.
(d)Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to an increased scope of scheduled outages.

Coal plant maintenance costs decreased in 2011 compared with 2010 primarily due to the timing of scheduled maintenance outages and non-outage boiler maintenance.

Depreciation

Depreciation increased by $5 million in 2012 compared with 2011 due to PP&E additions.

Depreciation increased by $9 million in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.

Taxes, Other Than Income

Taxes, other than income increased by $5 million in 2012 compared with 2011 due in part to a $2 million increase in property taxes resulting from property additions, higher assessed values and changes in property classifications to categories with higher tax rates.

Taxes, other than income increased by $5 million in 2011 compared with 2010 primarily due to a $4 million state coal tax credit that was applied to 2010 property taxes.  The remaining increase was due to higher assessments, primarily from significant property additions.

Other Income (Expense) - net

Other income (expense) - net decreased by $16 million in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset for previously recorded losses on interest rate swaps in 2010.

Interest Expense

The increase (decrease) in interest expense was due to:

   2012 vs. 2011 2011 vs. 2010
        
Interest rates (a) $ (2) $ (7)
Long-term debt balances (b)      2 
Other      3 
Total $ (2) $ (2)

(a)Interest expense decreased in 2011 compared with 2010 due to lower interest rates on first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates that were in place through October 2010.
(b)Interest expense increased in 2011 compared with 2010 due to lower long-term debt balances for the first ten months of 2010.
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Financial Condition

Liquidity and Capital Resources

LG&E expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities, including commercial paper issuances. Additionally, subject to market conditions, LG&E currently plans to access capital markets in 2013.

LG&E's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:

·changes in commodity prices that may increase the cost of producing or purchasing power or decrease the amount LG&E receives from selling power;
·operational and credit risks associated with selling and marketing products in the wholesale power markets;
·unusual or extreme weather that may damage LG&E's transmission and distribution facilities or affect energy sales to customers;
·reliance on transmission facilities that LG&E does not own or control to deliver its electricity and natural gas;
·unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·costs of compliance with existing and new environmental laws;
·any adverse outcome of legal proceedings and investigations with respect to LG&E's current and past business activities;
·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·a downgrade in LG&E's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt.

See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting LG&E's cash flows.

At December 31, LG&E had the following:

     
  2012  2011  2010 
          
Cash and cash equivalents $ 22  $ 25  $ 2 
Short-term investments (a)         163 
  $ 22  $ 25  $ 165 
          
Short-term debt (b) $ 55     $ 163 

(a)Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were purchased from the remarketing agent in 2008.  Such bonds were remarketed to unaffiliated investors in January 2011.  See Note 7 to the Financial Statements for additional information.
(b)Borrowings in 2012 were made under LG&E's commercial paper program and borrowings in 2010 were made under LG&E's syndicated credit facility.  See Note 7 to the Financial Statements for additional information.

The changes in LG&E's cash and cash equivalents position resulted from:

     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
              
Net cash provided by (used in) operating activities $ 308  $ 325  $ (8)  $ 189 
Net cash provided by (used in) investing activities   (289)   (42)   (63)    (107)
Net cash provided by (used in) financing activities   (22)   (260)   69     (83)
Net Increase (Decrease) in Cash and Cash Equivalents $ (3) $ 23  $ (2)  $ (1)
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Operating Activities

Net cash provided by operating activities decreased by 5%, or $17 million, in 2012 compared with 2011, primarily as a result of:
·Working capital cash flow changes declined by $65 million driven primarily by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010, and lower inventory levels in 2011 as compared with 2010 driven by lower gas prices.
·The decline was offset by $44 million increase in other operating cash flows driven by $43 million reduction in pension funding.

Net cash provided by operating activities increased by 80%, or $144 million, in 2011 compared with 2010, primarily as a result of:

·a decrease in working capital related to accounts receivable and unbilled revenues of $86 million primarily due to the timing of cash receipts and colder weather in December 2010 as compared with December 2009 and milder weather in December 2011 as compared with December 2010;
·an increase in net income adjusted for non-cash effects of $34 million (the recording of a regulatory asset for previously recorded losses on interest rate swaps of $22 million, deferred income taxes and investment tax credits of $17 million, depreciation of $9 million, partially offset by unrealized (gains) losses on derivatives of $14 million, defined benefit plans - expense of $3 million and other noncash items of $3 million);
·a decrease in cash outflows of $32 million due to lower inventory levels in 2011 as compared with 2010 driven by $21 million due to lower coal burn as a result of unplanned outages at the Mill Creek plant, $8 million for fuel inventory purchased in 2010 for TC2 that was not used until 2011 when TC2 began dispatch and $6 million for decreases in gas storage volumes;
·a decrease in cash refunded to customers of $25 million due to prior period over-recoveries related to the gas supply clause filings in 2009; and
·a decrease in cash outflows related to accrued taxes of $22 million due to the timing of payments of accrued tax liabilities in 2011 and 2010; partially offset by
·an increase in discretionary defined benefit plan contributions of $44 million made in order to achieve LG&E's long-term funding requirements; and
·an increase in working capital related to accounts payable of $41 million, which was driven primarily by the timing of cash payments and a decrease in natural gas purchases of $18 million in 2011 as compared with 2010 due to a decrease in combustion turbine generation as a result of the dispatch of TC2 beginning in January 2011.

Investing Activities

Net cash used in investing activities increased by $247 million, in 2012 compared with 2011, primarily as a result of:
·a decrease in the proceeds from the sale of other investments of $163 million in 2011; and
·an increase in capital expenditures of $90 million due primarily to construction of Cane Run Unit 7 and Mill Creek environmental air projects.
Net cash used in investing activities decreased by 75%, or $128 million, in 2011 compared with 2010, as a result of:

·proceeds from the sale of other investments of $163 million in 2011; and
·a decrease in capital expenditures of $24 million due primarily to TC2 being dispatched in 2011; partially offset by
·proceeds from the sale of assets of $48 million in 2010; and
·a decrease in restricted cash of $11 million.
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.

Financing Activities

Net cash used in financing activities was $22 million, in 2012 compared with $260 million in 2011, primarily as a result of changes in short-term debt.

In 2012, cash used in financing activities consisted of:
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·the payment of common stock dividends to LKE of $75 million; partially offset by
·the issuance of short-term debt in the form of commercial paper of $55 million.

Net cash used in financing activities was $260 million, in 2011 compared with $14 million in 2010, primarily as a result of changes in short-term debt.

In 2011, cash used in financing activities consisted of:

·a repayment on a revolving line of credit of $163 million;
·the payment of common stock dividends to LKE of $83 million;
·a net decrease in notes payable with affiliates of $12 million; and
·the payment of debt issuance and credit facility costs of $2 million.

In the two months of 2010 following PPL's acquisition of LKE, cash provided by financing activities of the Successor consisted of:
·the issuance of first mortgage bonds of $531 million after discounts;
·the issuance of debt of $485 million to a PPL affiliate to repay debt due to an E.ON AG affiliate upon the closing of PPL's acquisition of LKE; and
·a draw on a revolving line of credit of $163 million; partially offset by
·the repayment of debt to an E.ON AG affiliate of $485 million upon the closing of PPL's acquisition of LKE;
·the repayment of debt to a PPL affiliate of $485 million upon the issuance of first mortgage bonds;
·a net decrease in notes payable with affiliates of $130 million; and
·the payment of debt issuance and credit facility costs of $10 million.

In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:

·the payment of common stock dividends to LKE of $55 million and
·a net decrease in notes payable with affiliates of $28 million.

See "Forecasted Sources of Cash" for a discussion of LG&E's plans to issue debt securities, as well as a discussion of credit facility capacity available to LG&E.  Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.

LG&E had no long-term debt securities activity during the year.

See Note 7 to the Financial Statements for additional information about long-term debt securities.

Auction Rate Securities

At December 31, 2012, LG&E's tax-exempt revenue bonds that are in the form of auction rate securities and total $135 million continue to experience failed auctions.  Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures.  For the period ended December 31, 2012, the weighted-average rate on LG&E's auction rate bonds in total was 0.20%.

Forecasted Sources of Cash

LG&E expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper program, issuance of debt securities and operating cash flow.
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Credit Facilities

At December 31, 2012, LG&E's total committed borrowing capacity under its Syndicated Credit Facility and the use of this borrowing capacity were:

     Commercial Letters of Unused
   Capacity Paper Issued Credit Issued Capacity
          
Syndicated Credit Facility (a) (b) (c) $ 500  $  55     $ 445 

(a)The commitments under LG&E's Syndicated Credit Facility are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 6% of the total committed capacity available to LG&E.
(b)In November 2012, LG&E amended the Syndicated Credit Facility to extend the expiration date to November 2017.  In addition, LG&E increased the credit facility capacity to $500 million.
(c)LG&E pays customary fees under its syndicated credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to $500 million at an interest rate based on a market index of commercial paper issues.  At December 31, 2012, there was no balance outstanding.

See Note 7 to the Financial Statements for further discussion of LG&E's credit facilities.

Operating Leases

LG&E also has available funding sources that are provided through operating leases.  LG&E leases office space, gas storage and certain equipment.  These leasing structures provide LG&E additional operating and financing flexibility.  The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.

See Note 11 to the Financial Statements for further discussion of the operating leases.

Capital Contributions from LKE

From time to time LKE may make capital contributions to LG&E.  LG&E may use these contributions to fund capital expenditures and for other general corporate purposes.
Long-term Debt Securities

LG&E currently plans to issue, subject to market conditions, up to $350 million of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.

Forecasted Uses of Cash

In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, LG&E currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of debt securities.

Capital Expenditures

The table below shows LG&E's current capital expenditure projections for the years 2013 through 2017.

    Projected
    2013  2014  2015  2016  2017 
Capital expenditures (a)               
 Generating facilities $ 138  $ 111  $ 131  $ 225  $ 232 
 Distribution facilities   144    140    166    165    174 
 Transmission facilities   59    31    19    16    16 
 Environmental   324    336    249    186    42 
 Other   22    22    20    23    19 
  Total Capital Expenditures $ 687  $ 640  $ 585  $ 615  $ 483 
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(a)LG&E generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates.  The 2013 total excludes amounts included in accounts payable as of December 31, 2012.

LG&E's capital expenditure projections for the years 2013 through 2017 total approximately $3.0 billion.  Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.  This table includes current estimates for LG&E's environmental projects related to existing and proposed EPA compliance standards.  Actual costs may be significantly lower or higher depending on the final requirements and market conditions.  Environmental compliance costs incurred by LG&E in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.

LG&E plans to fund its capital expenditures in 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.

Contractual Obligations

LG&E hasTalen Energy Supply and its subsidiaries have assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, the2015, estimated contractual cash obligations of LG&E were:were as follows.
  Total 2016 2017-2018 2019-2020 After 2020
Long-term Debt (a) $4,228
 $396
 $429
 $1,423
 $1,980
Interest on Long-term Debt (b) 1,560
 236
 408
 306
 610
Operating Leases (c) 81
 19
 26
 10
 26
Purchase Obligations (d) 2,703
 621
 948
 319
 815
Other Long-term Liabilities Reflected on the Balance Sheet under GAAP (e)(f) 40
 40
 —
 —
 —
    Total Contractual Cash Obligations $8,612
 $1,312
 $1,811
 $2,058
 $3,431

    Total 2013  2014 - 2015 2016 - 2017 After 2017
                  
Long-term Debt (a) $ 1,109     $ 250     $ 859 
Interest on Long-term Debt (b)   839  $ 37    70  $ 66    666 
Operating Leases (c)   35    5    11    5    14 
Coal and Natural Gas Purchase               
  Obligations (d)   1,512    378    697    345    92 
Unconditional Power Purchase               
  Obligations (e)   719    21    42    44    612 
Construction Obligations (f)   735    382    273    80    
Pension Benefit Plan Obligations (g) 42    42          
Other Obligations (h)   8    2    4    2    
Total Contractual Cash Obligations $ 4,999  $ 867  $ 1,347  $ 542  $ 2,243 

(a)Reflects principal maturities only based on stated maturity dates. 2016 includes the $41 million redemption of the Senior Secured Notes of a Talen Ironwood Holdings, LLC subsidiary. See Note 75 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E.  LG&E has noadditional information. Talen Energy does not have any significant capital lease obligations.
(b)Assumes interest payments through stated maturity.maturity or earlier put dates. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c) 2016 includes the $14 million make whole premium paid in connection with the redemption of the Senior Secured Notes of a Talen Ironwood Holdings, LLC subsidiary. See Note 115 to the Financial Statements for additional information.
(d)Represents contracts to purchase coal, natural gas and natural gas transportation.  
(c)See Note 157 to the Financial Statements for additional information.
(d)The amounts primarily include as applicable, the purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the "Capital Expenditures" table presented above. Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. The amounts also include a $132 million contract related to the Ironwood facility, which was sold in February 2016.
(e)RepresentsThe amounts include Talen Energy's contributions committed to be made in 2016 for its pension plans.
(f)At December 31, 2015, total unrecognized tax benefits of $31 million were excluded from this table as management cannot reasonably estimate the amount and period of future minimum payments under OVEC power purchase agreements through June 2040.payments. See Note 154 to the Financial Statements for additional information.

(f)Represents construction commitments, including commitments for the Mill Creek environmental air projects, Cane Run Unit 7 and Ohio Falls refurbishment which are also reflected in the Capital Expenditures table presented above.
(g)Based on the current funded status of LG&E's qualified pension plan and LKE's qualified pension plan, which covers LG&E employees, no cash contributions are required.  See Note 13 to the Financial Statements for a discussion of expected contributions.
(h)Represents other contractual obligations.
Dividends/Distributions

Dividends

Talen Energy Corporation does not expect to pay dividends in 2016. From time to time, as determined by its Board of Directors, LG&E pays dividendsManagers, Talen Energy Supply may pay distributions to its sole shareholder, LKE.member. Certain of Talen Energy Supply's debt agreements include covenants that could effectively restrict the payment of distributions, loans or advances, either directly to Talen Energy Corporation or to Talen Energy Supply or one of its subsidiaries.

As discussed inSee "Item 1A. Risk Factors" and Note 75 to the Financial Statements LG&E's ability to pay dividends is limited under a covenant in its $500 million revolving line of credit facility.  This covenant restricts the debt to total capital ratio to not more than 70%.  See Note 7 to the Financial Statements for these and other restrictions related to distributions on capital interests for LG&E.Talen Energy.

Purchase or Redemption of Debt Securities

LG&ETalen Energy will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take actionpurchase or redeem these securities depending upon prevailing market conditions and available cash.

Rating Agency ActionsAgencies and Credit Considerations

Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of LG&E.  Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.

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A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of LG&E are based on information providedissued by LG&E and other sources.  The ratings of Moody's, S&P and Fitchrating agencies are not a recommendationrecommendations to buy, sell or hold any debt securities of LG&E.Talen Energy, and they are often based in part on information provided by Talen Energy and other sources. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.  TheTalen Energy's credit ratings of LG&Emay affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.borrowing.

The following table sets forth LG&E's securitythe credit ratings issued by Moody's and Standard & Poor's for outstanding debt securities or credit facilities of Talen Energy Supply as of December 31, 2012.2015.

Senior UnsecuredSenior SecuredCommercial Paper
 
Issuer Moody's S&P
FitchSenior Unsecured Moody'sBa3 S&PB+
Senior Secured FitchBaa2 Moody'sBB
Corporate Issuer Rating S&PBa2 FitchB+
Outlook Negative 
LG&EAA2A-A+P-2A-2F-2Stable

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In addition to the credit ratings noted above, the rating agencies took the following actions related to LG&E:

In February 2012, Fitch assigned ratings to LG&E's newly established commercial paper program.

In March 2012, Moody's affirmed the following ratings:
·     the long-term ratingsTable of the First Mortgage Bonds for LG&E;Contents

·     the issuer ratings for LG&E; and
·     the bank loan ratings for LG&E.

Also in March 2012, Moody's and S&P each assigned short-term ratings to LG&E's newly established commercial paper program.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A and 2007 Series B pollution control bonds.

In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.

In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlook for LG&E.

Ratings Triggers

LG&E has variousVarious derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage and interest rate instruments which contain provisions requiring LG&E to postthat require the posting of additional collateral, or permittingpermit the counterparty to terminate the contract, if LG&E'sthose contracts, upon a downgrade in Talen Energy Supply's credit rating were to fall below investment grade.rating.  See Note 1915 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been requiredrequirements for Talen Energy for derivative contracts in a net liability position at December 31, 2012.  At December 31, 2012, if LG&E's credit ratings had been below investment grade, the maximum amount that LG&E would have been required to post as additional collateral to counterparties was $57 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations, gas supply and interest rate contracts.2015.

Talen Energy has no credit rating triggers that, by themselves, would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.

Guarantees for Subsidiaries

Talen Energy Supply guarantees certain consolidated affiliate financing arrangements. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, accelerate maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. See Note 11 to the Financial Statements for additional information about guarantees.

Off-Balance Sheet Arrangements

LG&ETalen Energy has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 1511 to the Financial Statements for a discussion of these agreements.

Risk Management

Market Risk

Market Risk

See Notes 1, 1814 and 1915 to the Financial Statements for information about LG&E'sTalen Energy's risk management objectives, valuation techniques and accounting designations.

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The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions.  Actual future results may differ materially from those presented.  These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.

Commodity Price Risk (Non-trading)

LG&E's rates are set by regulatory commissionsTalen Energy's non-trading activity includes economic hedge transactions that address a specific risk.  This activity includes the changes in fair value of positions used to hedge a portion of the economic value of Talen Energy's competitive generation assets and the fuel costs incurred are directly recoverable from customers.  As a result, LG&Efull-requirement sales and retail contracts.  This economic activity is subject to commoditychanges in fair value due to market price risk for only a small portion of on-going business operations.  LG&E sells excess economic generation to maximize the valuevolatility of the physical assets at times when the assets are not required to serve LG&E's or KU's customers.input and output commodities (e.g., fuel and power).  See Note 1915 to the Financial Statements for additional disclosures.information.

To hedge the impact of market price volatility on Talen Energy's energy-related assets, liabilities and other contractual arrangements, Talen Energy subsidiaries both sell and purchase physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enter into financial exchange-traded and over-the-counter contracts.  Talen Energy's non-trading commodity derivative contracts range in maturity through 2020.

The balance and changefollowing table sets forth the changes in the net fair value of LG&E'snon-trading commodity derivative contracts for the periodsyears ended December 31.  See Notes 14 and 15 to the Financial Statements for additional information.
  Gains (Losses)
  2015 2014
Fair value of contracts outstanding at the beginning of the period $53
 $107
Contracts realized or otherwise settled during the period (133) 328
Fair value of new contracts entered into during the period (a) 5
 (12)
Other changes in fair value 220
 (370)
Fair value of contracts outstanding at the end of the period
$145
 $53


52

(a)
Represents the fair value of contracts at the end of the quarter of their inception. Includes the impact of contracts acquired as part of the RJS Power and MACH Gen acquisitions.

The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2015, based on the observability of the information used to determine the fair value.
 Net Asset (Liability)
 Maturity
Less Than
1 Year		 Maturity
1-3 Years		 Maturity
4-5 Years		 Maturity in Excess
of 5 Years		 Total Fair
Value
Source of Fair Value         
Prices based on significant observable inputs (Level 2)$89
 $—
 $7
 $—
 $96
Prices based on significant unobservable inputs (Level 3)31
 17
 1
 —
 49
Fair value of contracts outstanding at the end of the period$120
 $17
 $8
 $—
 $145

Talen Energy subsidiaries sell electricity, capacity and related services and buy fuel on a forward basis to hedge the value of energy from Talen Energy's generation assets.  If these Talen Energy subsidiaries were unable to deliver firm capacity and energy or to accept the delivery of fuel under their agreements, under certain circumstances they could be required to pay liquidated damages.  These damages would be based on the difference between the market price and the contract price of the commodity.  Depending on price changes in the wholesale energy markets, such damages could be significant.  Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties (or their counterparties) with which it has energy contracts and other factors could affect Talen Energy's ability to meet its obligations, and/or cause significant increases in the market price of replacement energy.  Although Talen Energy attempts to mitigate these risks, the company cannot assure that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future.

Commodity Price Risk (Trading)

Talen Energy's trading commodity derivative contracts range in maturity through 2019.  The following table sets forth changes in the net fair value of trading commodity derivative contracts for the years ended December 31.  See Notes 14 and 15 to the Financial Statements for additional information.
 Gains (Losses)
 2015 2014
Fair value of contracts outstanding at the beginning of the period$48
 $11
Contracts realized or otherwise settled during the period(68) (60)
Fair value of new contracts entered into during the period (a)4
 5
Other changes in fair value25
 92
Fair value of contracts outstanding at the end of the period$9
 $48

(a)
Represents the fair value of contracts at the end of the quarter of their inception.

The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2015, based on the observability of the information used to determine the fair value.
 Net Asset (Liability)
 Maturity
Less Than
1 Year		 Maturity
1-3 Years		 Maturity
4-5 Years		 Maturity
in Excess
of 5 Years		 Total Fair
Value
Source of Fair Value         
Prices based on significant observable inputs (Level 2)$6
 $—
 $(2) $—
 $4
Prices based on significant unobservable inputs (Level 3)5
 —
 —
 —
 5
Fair value of contracts outstanding at the end of the period$11
 $—
 $(2) $—
 $9

VaR Models

A VaR model is utilized to measure commodity price risk in competitive margins for the non-trading and trading portfolios.  VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level.  VaR is calculated using a Monte Carlo simulation technique based on a

53

five-day holding period at a 95% confidence level.  Given Talen Energy's hedging program, the non-trading VaR exposure is expected to be limited in the short-term.  The VaR for portfolios using end-of-month results for the year ended December 31, 2012, 2011 and 2010 are shown in the table below.2015 was as follows.
 Trading VaR Non-Trading VaR
95% Confidence Level, Five-Day Holding Period   
Period End$—
 $37
Average for the Period1
 18
High4
 37
Low—
 8

     Gains (Losses)
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
                 
Fair value of contracts outstanding at the beginning of the period    $ (1)       
Contracts realized or otherwise settled during the period      (3)     $ 3 
Fair value of new contracts entered into during the period             (4)
Other changes in fair value (a)      4  $ (1)    1 
Fair value of contracts outstanding at the end of the period    $  $ (1)  $ 
The trading portfolio includes all proprietary trading positions, regardless of the delivery period.  All positions not considered proprietary trading are considered non-trading.  The non-trading portfolio includes the entire portfolio, including generation, with delivery periods through the next 12 months.  Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets.  The fair value of the non-trading and trading FTR positions was insignificantat December 31, 2015.

Interest Rate Risk

(a)Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period.

Interest Rate Risk

LG&ETalen Energy, directly or through its subsidiaries, issues debt to finance its operations, which exposes it to interest rate risk.  LG&E utilizesTalen Energy may utilize various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio, adjust the duration of its debt portfolio and lock in components of current market interest rates in anticipation of future financing, when appropriate.  Risk limits under LG&E'sthe risk management programpolicy are designed to balance risk,mitigate interest rate exposure toand volatility in interest expense and changes in the fair value of LG&E's debt portfolio due to changes in the absolute level of interest rates.expense.

AtTalen Energy had no interest rate hedges outstanding at December 31, 20122015 and 2011, LG&E's2014.

Talen Energy is exposed to a potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.

LG&E is also exposedexpense and to changes in the fair value of its debt portfolio.  LG&EThe estimated thatimpact of a 10% decreaseadverse movement in interest rates at December 31, 2012,2015 would cause an insignificant increase in interest expense and a $119 million increase in the fair value of its debt portfolio by $27 million.  This estimate is unchanged fromdebt. At December 31, 2011.2014, the estimated impact of a 10% adverse movement in interest rates would cause an insignificant increase in interest expense and a $46 million increase in the fair value of debt.

NDT Funds - Securities Price Risk

LG&E had the following interest rate hedges outstanding at:
                    
   December 31, 2012 December 31, 2011
       Effect of a     Effect of a
     Fair Value, 10% Adverse   Fair Value, 10% Adverse
    Exposure Net - Asset Movement  Exposure Net - Asset Movement
   Hedged (Liability) (a) in Rates Hedged (Liability) (a) in Rates
Economic hedges                  
 Interest rate swaps (b) $ 179  $ (58) $ (3) $ 179  $ (60) $ (4)
Cash flow hedges                  
 Interest rate swaps (b)   150    7    (9)         
In connection with certain NRC requirements, Susquehanna Nuclear maintains trust funds to fund certain costs of decommissioning the Susquehanna Nuclear plant.  At December 31, 2015, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on the balance sheet.  The mix of securities is designed to provide returns sufficient to fund Susquehanna Nuclear's decommissioning and to compensate for inflationary increases in decommissioning costs.  However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates.  Talen Energy actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement.  At December 31, 2015, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $74 million reduction in the fair value of the trust assets compared with $73 million at December 31, 2014.  See Notes 14 and 19 to the Financial Statements for additional information regarding the NDT funds.

(a)Includes accrued interest.
Defined Benefit Plans - Securities Price Risk
(b)LG&E utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments.  These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing.  While LG&E is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic and cash flow hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities.  Sensitivities represent a 10% adverse movement in interest rates.  The positions outstanding at December 31, 2012 mature through 2043.

See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on Talen Energy plan assets.
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Credit Risk

LG&ECredit risk is exposed to potential lossesthe risk that Talen Energy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. LG&ETalen Energy maintains credit policiesprocedures with respect to counterparty credit (including requirements that counterparties maintain specified credit standards) and proceduresrequire other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, Talen Energy has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies. These

54

concentrations may impact Talen Energy's overall exposure to credit risk, including evaluatingpositively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Talen Energy includes the effect of credit ratings and financial information along with having certain counterparties post margin ifrisk on its fair value measurements to reflect the credit exposure exceeds certain thresholds.  LG&E is exposedprobability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint). In this case, Talen Energy would have to potential losses assell into a result of nonpayment by customers.  LG&E maintainslower-priced market or purchase in a higher-priced market. When necessary, Talen Energy records an allowance for doubtful accounts basedto reflect the probability that a counterparty will not pay for deliveries Talen Energy has made but not yet billed, which are reflected in "Unbilled revenues" on a historical charge-off percentage for retail customers.  Allowances for doubtful accounts from wholesale customers and miscellaneous receivables are based on specific identification by management.  Retail and wholesale customer accounts are written-off after four months of no payment activity.  Miscellaneous receivables are written-off as management determines them to be uncollectible.the Balance Sheets.

Certain of LG&E's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon LG&E's credit ratings from each of the major credit rating agencies.  See Notes 1814 and 19 to the Financial Statements for information regarding exposure and the risk management activities.

Related Party Transactions

LG&E is not aware of any material ownership interest or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with LG&E.  See Note 1615 to the Financial Statements for additional information on related party transactions.credit concentration and credit risk.

Acquisitions, Development and Divestitures

Environmental Matters

Protection ofTalen Energy from time to time evaluates opportunities for potential acquisitions, divestitures and development projects.  Development projects are reexamined based on market conditions and other factors to determine whether to proceed with the environment is a major priority for LG&E and a significant element of its business activities.  Extensive federal, state and local environmental laws and regulations are applicable to LG&E's air emissions, water discharges and the management of hazardous and solid waste, amongprojects, sell, cancel or expand them, execute tolling agreements or pursue other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material.  In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies.  Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions.  Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for LG&E's services.

Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to LG&E's generation assets and electricity transmission and distribution systems, as well as impacts on customers.  In addition, changed weather patterns could potentially reduce annual rainfall in areas where LG&E has hydro generating facilities or where river water is used to cool its fossil powered generators.  LG&E cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.

options.  See "Item 1. Business - Environmental Matters" and Note 156 to the Financial Statements for information on the RJS Power acquisition, the MACH Gen acquisition, the Talen Montana hydroelectric sale, and the announced divestitures of assets to satisfy a December 2014 FERC order approving the combination with RJS Power.

Environmental Matters

The following is a discussion of the more significant environmental matters impacting Talen Energy's business this fiscal year.  See "Item 1. Business" for additional information on environmental matters.
CSAPR

Annual and seasonal nitrogen oxide emission allowance trading programs, as well as annual sulfur dioxide emission allowance trading, commenced in 2015 for 28 states under the EPA's CSAPR Rule. In December 2015, the EPA proposed a "CSAPR Update Rule" which recommends more stringent ozone season nitrogen oxide budgets for 23 states, including several where Talen owns affected generation. Additional capital and/or operating and maintenance expenses could be imposed on Talen plants in Maryland, New Jersey, New York, Pennsylvania and Texas as a result of this action.
NAAQS

Regulations to address more stringent National Ambient Air Quality Standard (NAAQS) for ozone established by the EPA advanced in Pennsylvania and Maryland in 2015. In Pennsylvania, these regulations seek to establish reasonably available control technologies (RACT) for fossil-fuel fired power plants nitrogen oxide and volatile organic compound emissions.  Maryland coal plants operated at reduced nitrogen oxide emission rates during the 2015 ozone season as a result of an emergency action issued by the Governor (which later became a final rule), and in November 2015 the MDE promulgated additional nitrogen oxide regulations for Maryland coal plants that require even more stringent operations starting no later than June 2020. Actions were taken at the federal level in 2015 to tighten the NAAQS for ozone as well. More specifically, in October 2015, the EPA released a final rule establishing a more stringent national standard for ozone.
Pertaining to the EPA's 2010 NAAQS for sulfur dioxide, the EPA and Sierra Club entered into an approved consent decree on March 2, 2015 that establishes deadlines for remaining area designations. Several of Talen's affected plants are in undesignated areas.
Compliance with these regulations, or those that could be developed to address the EPA's 2010 sulfur dioxide NAAQS and/or 2015 ozone NAAQS, could lead to increased capital and/or operating and maintenance expenses for Talen Energy's fossil-fuel fired power plants.
MATS

Compliance with the EPA's MATS Rule commenced in April 2015 for those plants that did not receive a compliance extension. The rule has increased capital and operating and maintenance expenses for some of Talen Energy's power plants. The U.S. Supreme Court determined in June 2015 that the EPA acted unreasonably by refusing to consider costs when determining whether the MATS regulation was appropriate and necessary. The EPA responded with a proposed supplemental finding in November 2015 claiming that the regulation was appropriate and necessary based on cost. In December 2015, to address the

55

June 2015 Supreme Court action, the DC Circuit remanded the MATS Rule to the EPA to incorporate a revised appropriate and necessary finding.
Regional Haze

In September 2015, the Third Circuit Court of Appeals vacated portions of the EPA's approval of Pennsylvania's Regional Haze State Implementation Plan and remanded the Rule to the EPA for further consideration. Talen Energy is unable to determine at this time if the future impacts of Regional Haze on Talen Energy's Pennsylvania fossil-fuel fired power plants will have a material adverse effect on its financial condition or results of operations.

GHG Regulations

The EPA's final rules for new and existing power plants were published in the Federal Register in October 2015, along with a proposed federal implementation plan for those states that fail to submit an acceptable state implementation plan for the existing plant rule. EPA's existing plant rule has been stayed by the U.S. Supreme Court until all legal challenges to the rule have been resolved. The new plant rule remains in effect and challenges are also outstanding in federal court. Talen Energy is unable to determine if the rules will have a material adverse effect on Talen Energy's financial condition or results of operations, but increased capital and operating and maintenance costs could be imposed.
Exemptions for Startup, Shutdown and Malfunction Events

In June 2015, the EPA published a Final Rule which prohibits states from exempting startup, shutdown and malfunction events from compliance requirements in SIPs. Revisions to SIPs or other regulations in states where Talen Energy operates could impact operations and financial conditions.
CCRs

The EPA's final rule regulating CCRs as non-hazardous wastes, which imposes extensive new self-implementing requirements on CCR impoundments and landfills, became effective in October 2015. Talen Energy expects that its plants using surface impoundments for management and disposal of CCRs, or that previously managed CCRs and continue to manage wastewaters, will be most impacted by this rule. Talen Energy anticipates incurring capital, operating and/or maintenance costs to address other provisions of the rule, such as groundwater monitoring and disposal facility modifications. The final CCR Rule is being challenged in federal court. During 2015, an increase of $41 million was recorded to existing AROs. Further changes to AROs may be required as estimates are refined and compliance with the rule continues.
ELGs and Standards

The EPA's final ELG regulations that revise discharge limitations for steam electric generation wastewater permits were published in the Federal Register in November 2015. The regulations contain requirements that could significantly impact Talen Energy's coal-fired plants.  At this point, Talen Energy is unable to estimate a range of reasonably possible compliance costs. The regulations are being challenged in federal court.
Waters of the United States (WOTUS)

In June 2015, the EPA and the U.S. Army Corps of Engineers published their final rule redefining the term WOTUS, and in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order preventing the EPA from implementing the rule nationwide. In the event the stay is lifted, and the regulation survives separate legal challenges, the redefinition could impact future development actions, such as plant and gas infrastructure expansions.

New Accounting Guidance

See Notes 1 and 2421 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.

Application of Critical Accounting Policies

Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to an understanding of the reported financial condition or results of operations, and require management to make estimates or other judgments of matters that are inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a

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significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). LG&E's seniorSenior management has reviewed with Talen Energy Corporation's Audit Committee these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
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Revenue Recognition - Unbilled Revenue
them.

Revenues relatedPrice Risk Management

See "Price Risk Management" in Note 1 to the sale of energy are recorded when service is rendered or when energy is delivered to customers.  Because customers of LG&E's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, LG&E records estimates for unbilled revenues at the end of each reporting period.  Such unbilled revenue amounts reflect estimates of the amount of electricity and gas delivered to customers since the date of the last reading of their meters.  The unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather and where applicable, the impact of weather normalization or other regulatory provisions of rate structures.  In addition to the unbilled revenue accrual resulting from cycle billing, LG&E makes additional accruals resulting from the timing of customer bills.  The accrual of unbilled revenues in this manner properly matches revenues and related costs.  At December 31, 2012 and 2011, LG&E had unbilled revenue balances of $72 million and $65 million.
Defined Benefits
Financial Statements, as well as "Risk Management" above.

LG&E sponsorsDefined Benefits

Talen Energy Supply and participatescertain of its subsidiaries sponsor or participate in, as applicable, various qualified funded and non-qualified unfunded defined benefit pension plans and participates in aboth funded and unfunded other postretirement benefit plan.plans. These plans are applicable to the majority of theTalen Energy's employees of LG&E.  The plans LG&E participates in are sponsored by LKE.  LKE allocates a portion of the liability and net periodic defined benefit pension and other postretirement costs of certain plans to LG&E based(based on its participation.  LG&Eeligibility for their applicable plans). Talen Energy records an asset or liability, with an offsetting entry to AOCI to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assetsthat it or liabilities.its subsidiaries sponsor. Consequently, the funded status of all sponsored defined benefit plans is fully recognized on the Balance Sheets. See Note 139 to the Financial Statements for additional information about the plans and the accounting for defined benefits.benefits including a discussion of the newly created pension and other postretirement benefit plans sponsored by Talen Energy Supply that replaced Talen Energy Supply's participation in similar PPL plans effective with the June 1, 2015 spinoff.

CertainManagement makes certain assumptions are made by LKE and LG&E regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates.AOCI. These amounts in regulatory assets and liabilitiesAOCI are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
·Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future.  The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  These projected returns reduce the net benefit costs LG&E records currently.
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets that will be earned over the life of each plan. These projected returns reduce the net periodic defined benefit costs currently recorded.

·Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.

In selecting a discount rate foraddition to the economic assumptions above that are evaluated annually, management must also make assumptions regarding the life expectancy of employees covered under their defined benefit pension and other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors adopted the mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables) for all applicable defined benefit pension and other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors also selected the IRS BB 2-Dimensional mortality improvement scale on a generational basis for all applicable defined benefit pension and other postretirement benefit plans. These mortality assumptions reflect the recognition of both improved life expectancies and the expectation of continuing improvements in life expectancies.

For the applicable periods ended December 31, 2015, Talen Energy's defined benefit pension and other postretirement benefit plans LKE and LG&Eincurred actuarial losses of $50 million primarily due to lower actual return on plan assets compared to the expected return on plan assets partially offset by an increase in the discount rate.

In selecting the discount rates for applicable defined benefit plans, the plan sponsors start with a cash flow analysis of the expected benefit payment stream for their plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. Individual bonds are then selected based on the timing of each

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plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.  At December 31, 2012, LKE decreased

To determine the discount rate for its pensionexpected return on plan from 5.12% to 4.26%.  LG&E decreasedassets, the discount rate for its pension plan from 5.05% to 4.20%.  LKE decreasedsponsors project the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
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The expected long-term rates of return for LKE's and LG&E's defined benefit pension plans and LKE's defined other postretirement benefiton plan have been developedassets using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE and LG&E management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific current and expected asset allocation isallocations are also considered in developing a reasonable return assumption. At December 31, 2012, LKE's and LG&E's expected return on plan assets decreased from 7.25% to 7.10%.

In selecting a rate of compensation increase, LKE and LG&Ethe plan sponsors consider past experience in light of movements in inflation rates. At December 31, 2012, LKE's

The following table provides the weighted-average assumptions used for discount rate, expected return on plan assets and LG&E's rate of compensation increase remained at 4.00%.December 31, 2015.
Assumption
Discount Rate
Pension4.65%
Other Postretirement4.60%
Expected return on plan assets
Pension7.00%
Other Postretirement6.37%
Rate of compensation increase
Pension3.98%
Other Postretirement3.98%

In selecting health care cost trend rates, LKE considersthe plan sponsors consider past performance and forecasts of health care costs. At December 31, 2012, LKE's2015, the health care cost trend rates for all plans were 8.00%6.8% for 2013,2016, gradually declining to 5.50% for 2019.an ultimate trend rate of 5.0% in 2020.

A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilitiespension obligations, reported annual net periodic pension costs and related AOCI. At December 31, 2015, the accrued pension obligations and related items and the portions related to the most significant plan were recorded in the financial statements as follows.
  Total Most Significant Plan
Balance Sheet:    
Accrued pension obligations $(340) $(323)
AOCI (pre-tax) 453
 390
Statement of Income:    
Pension costs $48
 $28

The following table reflects the impact of changes in certain assumptions for Talen Energy's most significant plan. The table reflects either an increase or assets,decrease in each assumption. The inverse of this change would impact the accrued pension obligation, reported annual net periodic defined benefit costs and regulatory assets and liabilities for LG&E.  While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for LG&EAOCI by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.assumption.
   Increase (Decrease)
Actuarial assumptionSensitivity Accrued Pension Obligation AOCI (pre-tax) Pension Costs
Discount rate(0.25)% $51
 $51
 $5
Expected return on plan assets(0.25)% n/a
 n/a
 3
Rate of compensation increase0.25 % 7
 7
 2

At December 31, 2012, the defined benefit plans were recorded as follows:

Pension liabilities$ 102 
Other postretirement benefit liabilities 81 

The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on LG&E's primary defined benefit plans.

  Increase (Decrease)
     Impact on    Impact on
  Change in defined benefit Impact on regulatory
Actuarial assumption assumption liabilities OCI assets
             
Discount Rate  (0.25)% $ 21     $ 21 
Rate of Compensation Increase  0.25%   2       2 
Health Care Cost Trend Rate (a)  1%   1       1 

(a)Only impacts other postretirement benefits.

In 2012, LG&E recognized net periodic defined benefit costs charged to operating expense of $18 million.  This amount represents a $3 million decrease from 2011.  This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $21 million, a reduction in the amortization of outstanding losses and lower interest cost.

The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on LG&E's primary defined benefit plans.

Actuarial assumption  Change in assumption  Impact on defined benefit costs
       
Discount Rate  (0.25)% $ 2 
Expected Return on Plan Assets  (0.25)%   1 
Rate of Compensation Increase  0.25%   
Health Care Cost Trend Rate (a)  1%   

(a)Only impacts other postretirement benefits.
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Asset Impairment (Excluding Investments)

Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:

·a significant decrease in the market price of an asset;
a significant decrease in the market price of an asset;
·a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;

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·a significant adverse change in legal factors or in the business climate;
Table of Contents

a significant adverse change in legal factors or in the business climate;
·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value. Management must make significant judgments to estimate future cash flows, including the useful lives of long-livedthe assets, the fair value offorward prices for energy, capacity and fuel in the markets where the assets are utilized, the amount of capital and operations and maintenance spending and management's intent tointended use of the assets. Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used, taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including thean assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantlymaterially different results than those identified and recorded in the financial statements.

For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized in future periods for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized. If the asset (disposal group) no longer qualifies for classification as held for sale, it must be reclassified as held and used and its carrying value must be adjusted to the lower of its estimated fair value at that time or its carrying value when initially classified as held for sale adjusted for depreciation through the reclassification date.

For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, LG&ETalen Energy considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determinedetermining the present value of the cash flow streams.streams using risk-adjusted discount rates.
In 2015, Talen Energy recorded pre-tax impairment charges of $189 million ($113 million after-tax) applicable to certain assets (classified as held and used and held for sale). See Notes 14 and 16 to the Financial Statements for details on the evaluation and charges recorded.

In 2012, LG&E did not recognize an impairment of any long-lived assets.

Goodwill is tested for impairment at the reporting unit level. LG&E'sTalen Energy has determined its reporting unit has been determinedunits to be at the same level as its operating segment level.segments. At December 31, 2015, Talen Energy is organized in two operating segments/reporting units: East and West, primarily based on geographic location. Prior to the RJS acquisition, Talen Energy operated within a single operating segment/reporting unit. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the reporting unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.

Beginning in 2012, LG&ETalen Energy may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessmentevaluation and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value of thea reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if LG&E concludes it is more likely than not the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.

When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, LG&E identifiesTalen Energy determines whether a potential impairment exists by comparing the estimated fair value of LG&E (the goodwilla reporting unit)unit with its carrying amount, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.


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The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value of a reporting unit is allocated to all of LG&E'sthe assets and liabilities of that reporting unit as if LG&Ethe reporting unit had been acquired in a business combination and the estimated fair value of LG&Ethe reporting unit was the price paid.paid to acquire the reporting unit. The excess of the estimated fair value of LG&Ea reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of LG&E'sthe reporting unit's goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of LG&E'sthe reporting unit's goodwill.

LG&E elected to perform the two-step quantitativeIn 2015, Talen Energy recorded pre-tax goodwill impairment testcharges of goodwill in the fourth quarter of 2012 and no impairment was recognized.  Management used both discounted cash flows and market multiples,$465 million ($444 million after-tax), which required significant assumptions, to estimate the fair value of LG&E.  Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes.  For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihoodfully impaired all of the uncertain future eventsgoodwill previously recorded on the balance sheet and (2)assigned to the amount of the loss can be reasonably estimated.  Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured.  Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.

The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient.  All three of these aspects require significant judgment by management.  Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.

In 2012, no significant adjustments were made to LG&E's existing contingencies.

Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual.  Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred.  Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur."

When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable.  The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated.  The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved, LG&E makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate.  This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.

East segment/reporting unit. See Note 1516 to the Financial Statements for additional information.details on the evaluation and charges recorded.

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Asset Retirement Obligations

LG&E isARO liabilities are required to recognize a liabilitybe recognized for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocatedamortized to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statementsstatement of Income,income, for changes in the obligation due to the passage of time. Since costs of removal are collected in rates, the accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact.  The regulatory asset created by the regulatory credit is relieved when the ARO has been settled.  An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated.  See Note 21 to the Financial Statements for related disclosures.

In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROsthe ARO and the related assets,capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the obligations.ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset.

At December 31, 2012, LG&E had AROs comprised of current2015, the total recorded balances and noncurrent amounts, totaling $62 million recordedinformation on the Balance Sheet.  Of the total amount, $39 million, or 63%, relates to LG&E's ash ponds, landfills and natural gas mains.  most significant recorded AROs were as follows.

  Most Significant AROs
Total AROs Recorded Amount Recorded % of Total Description
$501
 $399
 79.6% Nuclear decommissioning

The most significant assumptions surrounding AROs are the forecasted retirement costs (including the settlement dates and the timing of cash flows), the discount rates and the inflation rates. A varianceAt December 31, 2015, a 10% change to retirement costs, a 0.25% decrease in the forecasted retirement costs, the discount ratesrate or a 0.25% increase in the inflation rates couldrate would not have a significant impact on the ARO liabilities.liabilities and would not cause a significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability.

The following chart reflectsSee Note 18 to the sensitivities related to LG&E's ARO liabilitiesFinancial Statements for ash ponds, landfills and natural gas mains at December 31, 2012:additional information on AROs.

  Change in Impact on
   Assumption ARO Liability
       
Retirement Cost  10% $5
Discount Rate  (0.25)%  1
Inflation Rate  0.25%  5
Income Taxes

Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination ofvaluation allowances that may be required to offset the related deferred tax assets, liabilities and valuation allowances.assets.

Significant management judgment is requiredIn order to determine the amount of benefit to be recognized relatedin relation to an uncertain tax position.  Tax positions are evaluated followingposition, Talen Energy uses a two-step process.process to evaluate tax positions. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured atas the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

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At December 31, 2012, LG&E's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million.  This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
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The balance sheet classification2015, Talen Energy had $31 million of unrecognized tax benefits and the need for valuation allowancesrecorded related to reduce deferred tax assets also require significant management judgment.  acquired with MACH Gen. Unrecognized tax benefits are classified as currentrecorded at December 31, 2014 were settled with taxing authorities and PPL prior to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.  June 1, 2015 spinoff from PPL.

Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the ability to carryback attributes, the reversal of temporary differences, future taxable income, and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances. The amount of net deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.

As a result of management's assessment of the realization of deferred tax assets, a valuation allowance of $10 million was recorded at December 31, 2015, primarily related to MACH Gen net operating losses in states where it is expected that a portion of the losses will expire unutilized.

See Note 54 to the Financial Statements for related disclosures.
Regulatory Assets and Liabilities
additional information on income taxes.

LG&EBusiness Combinations - Purchase Price Allocation

On June 1, 2015, substantially contemporaneous with the spinoff by PPL to form Talen Energy, RJS Power was contributed by the Riverstone Holders to become a subsidiary of Talen Energy Supply. Additionally, on November 2, 2015, Talen Energy completed the acquisition of the membership interests of MACH Gen. In accordance with accounting guidance on business combinations, the identifiable assets acquired and the liabilities assumed were measured at fair value at the acquisition date. Fair value is defined as the price that would be received to sell an asset or paid to transfer a cost-based rate-regulated utility.  Asliability in an orderly transaction between market participants. The excess of the purchase price over the estimated fair value of the identifiable net assets was recorded as goodwill.

The determination and allocation of fair value to the identifiable assets acquired and liabilities assumed was based on various assumptions and valuation methodologies requiring considerable management judgment, including estimates based on key assumptions of the acquisition, and historical and current market data. The most significant variables in these valuations were the discount rates, the number of years on which to base cash flow projections, as well as the assumptions and estimates used to determine cash inflows and outflows. Although the assumptions were reasonable based on information available at the dates of the acquisitions, actual results may differ from the forecasted amounts and the difference could be material.

The fair value of intangible assets and liabilities (e.g. contracts that have favorable or unfavorable terms relative to market), including coal contracts, a result,pipeline lease and an ash site permit, have been reflected on the effects of regulatory actions are required to be reflected in the financial statements.  Assetsbalance sheet. These intangible assets and liabilities are recorded that result frombeing amortized over the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates.  Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.  In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.  The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC and the KPSC.related contracts' terms.

Management continually assesses whetherGoodwill is measured as the regulatoryexcess of consideration transferred over the net of the acquisition date fair value of the assets are probableacquired and liabilities assumed. Goodwill related to the RJS acquisition of future recovery by considering factors such as changes$393 million was assigned to the East segment. There was no goodwill recorded in the applicable regulatoryprovisional purchase price allocation related to the MACH Gen acquisition. During the third quarter of 2015, impairment testing was completed and political environments,it was determined that all goodwill was impaired and was written off, including the abilitygoodwill recorded related to recover costs through regulated rates, recent rate ordersthe RJS acquisition. See Note 16 to other regulated entitiesthe Financial Statements for additional information regarding the goodwill impairment and Note 6 to the status of any pending or potential deregulation legislation.  Based on this continual assessment, management believesFinancial Statements for additional information regarding the existing regulatory assets are probable of recovery.  This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future.  If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income.  Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.purchase price allocations.

At December 31, 2012, LG&E had regulatory assets of $419 million and regulatory liabilities of $475 million.  All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.

See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.regarding the acquisitions.

Other Information

PPL'sTalen Energy Corporation's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.  See "Item 14. Principal Accounting Fees and Services" for more information.


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KENTUCKY UTILITIES COMPANY

Item 7.  Management's Discussion and AnalysisTable of Financial Condition and Results of Operations

The information provided in this Item 7 should be read in conjunction with KU's Financial Statements and the accompanying Notes.  Capitalized terms and abbreviations are defined in the glossary.  Dollars are in millions, unless otherwise noted.

"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:

·  "Overview" provides a description of KU and its business strategy, a summary of Net Income and a discussion of certain events related to KU's results of operations and financial condition.

·  "Results of Operations" provides a summary of KU's earnings and a description of key factors expected to impact future earnings.  This section ends with explanations of significant changes in principal items on KU's Statements of Income, comparing 2012 with 2011 and 2011 with 2010.

·  "Financial Condition - Liquidity and Capital Resources" provides an analysis of KU's liquidity position and credit profile.  This section also includes a discussion of forecasted sources and uses of cash and rating agency actions.

·  "Financial Condition - Risk Management" provides an explanation of KU's risk management programs relating to market and credit risk.

·  "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of KU and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.

Overview

Introduction

KU, headquartered in Lexington, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy in Kentucky, Virginia and Tennessee.  KU and its affiliate, LG&E, are wholly owned subsidiaries of LKE.  LKE, a holding company, became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010.  Following the acquisition, both KU and LG&E continue operating as subsidiaries of LKE, which is now an intermediary holding company in PPL's group of companies.  Refer to "Item 1. Business - Background" for a description of KU's business.

Business Strategy

KU's overall strategy is to provide reliable, safe, competitively priced energy to its customers and reasonable returns on regulated investments to its shareowner.

A key objective for KU is to maintain a strong credit profile through managing financing costs and access to credit markets.  KU continually focuses on maintaining an appropriate capital structure and liquidity position.

Successor and Predecessor Financial Presentation

KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor.  Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting.  Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of KU have not changed as a result of the acquisition.
Financial and Operational Developments

Net Income

Net Income for 2012, 2011 and 2010 was $137 million, $178 million and $175 million.  Earnings in 2012 decreased 23% from 2011 and earnings in 2011 increased 2% from 2010.

See "Results of Operations" for a discussion and analysis of KU's earnings.

Rate Case Proceedings

In June 2012, KU filed a request with the KPSC for an increase in annual base electric rates of approximately $82 million.  In November 2012, KU along with all of the parties filed a unanimous settlement agreement.  Among other things, the settlement provided for increases in annual base electric rates of $51 million.  The settlement agreement also included revised depreciation rates that result in reduced annual depreciation expense of approximately $10 million. The settlement agreement included an authorized return on equity of 10.25%.  On December 20, 2012, the KPSC issued an order approving the provisions in the settlement agreement.  The new rates became effective on January 1, 2013.

Equity Method Investment

KU owns 20% of the common stock of EEI.  Through a power marketer affiliated with its majority owner, EEI sells its output to third parties.  KU's investment in EEI is accounted for under the equity method of accounting.  KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.  During the fourth quarter of 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred.  Accordingly, KU recorded a $15 million impairment charge, net of taxes, related to this investment as of December 31, 2012, bringing the investment balance to zero.  The impairment charge is shown in the line "Other-Than-Temporary Impairments" on the Statement of Income for the year ended December 31, 2012.            

Commercial Paper

In February 2012, KU established a commercial paper program for up to $250 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by KU's Syndicated Credit Facility.  At December 31, 2012, KU had $70 million of commercial paper outstanding.

Terminated Bluegrass CTs Acquisition

In September 2011, KU and LG&E entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals.  In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs.  In November 2011, KU and LG&E filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs.  In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns.  After a review of potentially available mitigation options, KU and LG&E determined that the options were not commercially justifiable.  In June 2012, KU and LG&E terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.

Cane Run Unit 7 Construction

In September 2011, KU and LG&E filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7.  In May 2012, the KPSC issued an order approving the request.  KU will own a 78% undivided interest and LG&E will own a 22% undivided interest in the new generating unit.  A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings.  KU and LG&E commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015.  The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.

In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, KU anticipates retiring two older coal-fired electric generating units at the Green River plant, which have a combined summer capacity rating of 163 MW.  In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.

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Future Capacity Needs

In addition to the construction of a combined cycle gas unit at the Cane Run station, KU and LG&E continue to assess future capacity needs.  As a part of the assessment, KU and LG&E issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.


Results of Operations

As previously noted, KU's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010.  See "Overview - Successor and Predecessor Financial Presentation" for further information.

The utility business is affected by seasonal weather.  As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year.  Revenue and earnings are generally higher during the first and third quarters and lower during the second and fourth quarters due to weather.

The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:

Earnings             
   Successor  Predecessor
        Two Months  Ten Months
  Year Ended Year Ended Ended  Ended
  December 31, December 31, December 31,  October 31,
   2012  2011  2010   2010 
               
Net Income $ 137  $ 178  $ 35   $ 140 

The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.

  2012 vs. 2011 2011 vs. 2010
     
Margins $ (10) $ 52 
Other operation and maintenance   (16)   (12)
Depreciation   (6)   (28)
Taxes, other than income   (4)   (9)
Other Income (Expense) - net   (7)   (2)
Interest Expense   1    8 
Income Taxes   16    (6)
Special items, after-tax   (15)   
Total $ (41) $ 3 

As a result of low energy prices and environmental regulations, KU assessed the recoverability of its equity method investment in EEI.  KU determined it was impaired, and recorded a $15 million impairment charge, net of taxes, as of December 31, 2012.  This impairment is considered a special item by management.

·See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins.

·Higher other operation and maintenance in 2012 compared with 2011 primarily due to $8 million of higher coal plant maintenance costs related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.

Higher other operation and maintenance in 2011 compared with 2010 primarily due to $19 million of higher coal plant maintenance costs related to an increased scope of scheduled outages and higher variable costs from increased generation due to TC2 commencing dispatch in January 2011.  This increase was partially offset by a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.

·Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.

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·Lower interest expense in 2011 compared with 2010 primarily due to $18 million less expense primarily related to lower interest rates on the first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates in place through October 2010.  This decrease was partially offset by $8 million of higher expense resulting from higher long-term debt balances.

·Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income.

2013 Outlook

Excluding special items, KU projects higher earnings in 2013 compared with 2012, primarily driven by electric base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.

Earnings in future periods are subject to various risks and uncertainties.  See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.

Statement of Income Analysis --

Margins

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance.  Other companies may use different measures to analyze and to report on the results of their operations.  Margins is a single financial performance measure of KU's electricity generation, transmission and distribution operations.  In calculating this measure, fuel and energy purchases are deducted from revenues.  In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset.  These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives.  Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation."  As a result, this measure represents the net revenues from KU's operations.  This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.

Reconciliation of Non-GAAP Financial Measures

The following tables reconcile "Operating Income" to "Margins" as defined by KU for 2012, 2011 and 2010.

      2012 Successor   2011 Successor
           Operating        Operating
      Margins Other (a) Income (b)   Margins Other (a) Income (b)
                   
Operating Revenues $ 1,524     $ 1,524    $ 1,548     $ 1,548 
Operating Expenses                    
 Fuel   498       498      516       516 
 Energy purchases   109       109      112       112 
 Other operation and maintenance   55  $ 329    384      49  $ 313    362 
 Depreciation   49    144    193      48    138    186 
 Taxes, other than income      23    23         19    19 
   Total Operating Expenses   711    496    1,207      725    470    1,195 
Total $ 813  $ (496) $ 317    $ 823  $ (470) $ 353 
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      Successor  Predecessor
      Two Months Ended December 31, 2010  Ten Months Ended October 31, 2010
           Operating        Operating
      Margins Other (a) Income (b)  Margins Other (a) Income (b)
                   
Operating Revenues $ 263     $ 263   $ 1,248     $ 1,248 
Operating Expenses                   
 Fuel   78       78     417       417 
 Energy purchases   28       28     147       147 
 Other operation and maintenance   6  $ 59    65     29  $ 242    271 
 Depreciation   6    20    26     29    90    119 
 Taxes, other than income      1    1        9    9 
   Total Operating Expenses   118    80    198     622    341    963 
Total $ 145  $ (80) $ 65   $ 626  $ (341) $ 285 

(a)Represents amounts excluded from Margins.
(b)As reported on the Statements of Income.

Changes in Non-GAAP Financial Measures

Margins decreased by $10 million for 2012 compared with 2011, primarily due to $10 million of lower retail margins, as volumes were impacted by unseasonably mild weather during the first four months of 2012.  Total heating degree days decreased 9% compared to 2011, partially offset by a 4% increase in cooling degree days.

Margins increased by $52 million for 2011 compared with 2010.  New KPSC rates went into effect on August 1, 2010, contributing to an additional $64 million in operating revenue over the prior year.  Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.

Other Operation and Maintenance     
       
The increase (decrease) in other operation and maintenance was due to:
   
 2012 vs. 2011 2011 vs. 2010
       
Coal plant maintenance (a)$ 17  $ 9 
Distribution maintenance (b)  8    
Administrative and general (c)  (5)   7 
Fuel for generation (d)     6 
Steam operation (e)     10 
Other generation maintenance     (2)
Other  2    (4)
Total$ 22  $ 26 

(a)Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to $8 million of expenses related to an increased scope of scheduled outages, as well as $5 million of increased maintenance on the scrubber system and primary fuel combustion system at the Ghent plant.

Coal plant maintenance costs increased in 2011 compared with 2010 primarily due to $8 million of expenses related to an increased scope of scheduled outages.
(b)Distribution maintenance increased in 2012 compared with 2011 primarily due to a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
(c)Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost.

Administrative and general costs increased in 2011 compared with 2010 due to higher outside services costs of $2 million, higher labor costs of $1 million and higher pension costs of $1 million.
(d)Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period.
(e)Steam operation costs increased in 2011 compared with 2010 due to increased generation as a result of TC2 commencing dispatch in 2011.
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Depreciation

The increase (decrease) in depreciation was due to:

  2012 vs. 2011 2011 vs. 2010
       
TC2 (dispatch began in January 2011)   $ 25 
E.W. Brown sulfur dioxide scrubber equipment (placed in-service in June 2010)     8 
Other additions to PP&E$ 7    8 
Total$ 7  $ 41 

Taxes, Other Than Income

Taxes, other than income increased by $9 million in 2011 compared with 2010, primarily due to a $5 million state coal tax credit that was applied to 2010 property taxes.  The remaining increase was due to higher assessments, primarily from significant property additions.

Other Income (Expense) - net

Other income (expense) - net decreased by $7 million in 2012 compared with 2011 primarily due to $8 million losses from the EEI investment recorded in 2012.

Other-Than-Temporary Impairments

Other-than-temporary impairments increased by $25 million in 2012 compared with 2011 due to the $25 million pre-tax impairment of the EEI investment.  See Notes 1 and 18 to the Financial Statements for additional information.

Interest Expense

Interest expense decreased by $8 million in 2011 compared with 2010, primarily due to $18 million less expense primarily related to lower interest rates on the first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates in place through October 2010.  This decrease was partially offset by $8 million of higher expense resulting from higher long-term debt balances.

Income Taxes

Income taxes decreased by $26 million in 2012 compared with 2011, primarily due to the decrease in pre-tax income.

Income taxes increased by $6 million in 2011 compared with 2010, primarily due to the increase in pre-tax income.

Financial Condition

Liquidity and Capital Resources

KU expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, its credit facilities and commercial paper issuances.  Additionally, subject to market conditions, KU currently plans to access capital markets in 2013.

KU's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:

·changes in commodity prices that may increase the cost of producing or purchasing power or decrease the amount KU receives from selling power;
·operational and credit risks associated with selling and marketing products in the wholesale power markets;
·unusual or extreme weather that may damage KU's transmission and distribution facilities or affect energy sales to customers;
·reliance on transmission facilities that KU does not own or control to deliver its electricity;
·unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity;
·the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses;
·costs of compliance with existing and new environmental laws;

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·any adverse outcome of legal proceedings and investigations with respect to KU's current and past business activities;
·deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and
·a downgrade in KU's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt.

See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting KU's cash flows.

At December 31, KU had the following:

  2012  2011  2010 
          
Cash and cash equivalents $ 21  $ 31  $ 3 
          
Short-term debt (a) $ 70       

(a)Represents borrowings made under KU's commercial paper program.  See Note 7 to the Financial Statements for additional information.

The changes in KU's cash and cash equivalents position resulted from:

     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
              
Net cash provided by operating activities $ 500  $ 444  $ 30   $ 344 
Net cash provided by (used in) investing activities   (480)   (279)   (89)    (340)
Net cash provided by (used in) financing activities   (30)   (137)   58     (2)
Net Increase (Decrease) in Cash and Cash Equivalents $ (10) $ 28  $ (1)  $ 2 

Operating Activities

Net cash provided by operating activities increased by 13%, or $56 million, in 2012 compared with 2011, primarily as a result of:
·Other operating cash flows increased by $45 million driven by a $29 million reduction in pension funding.
·Working capital cash flows increased by $11 million driven by lower income tax payments as a result of lower taxable income in 2012, offset by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010.
Net cash provided by operating activities increased by 19%, or $70 million, in 2011 compared with 2010, primarily as a result of:

·an increase in net income adjusted for non-cash effects of $115 million (deferred income taxes and investment tax credits of $81 million and depreciation of $41 million, partially offset by defined benefit plans - expense of $2 million and other noncash items of $19 million);
·a net decrease in working capital related to unbilled revenues of $21 million due to colder weather in December 2010 as compared with December 2009, and milder weather in December 2011 as compared with December 2010; partially offset by
·an increase in discretionary defined benefit plan contributions of $30 million made in order to achieve KU's long-term funding requirements;
·the timing of ECR collections of $28 million; and
·an increase in cash outflows related to accrued taxes of $28 million due to an accrual in excess of payments made in 2010 for the 2010 tax year and the payment of the 2010 tax liability in 2011, along with payments made in 2011 over the accrual for the 2011 tax year.
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Investing Activities

Net cash used in investing activities increased by 72%, or $201 million, in 2012 compared with 2011, as a result of an increase in capital expenditures of $201 million, primarily due to coal combustion residuals projects at Ghent and E.W. Brown, construction of Cane Run Unit 7 and Ghent environmental air projects.

See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.

Net cash used in investing activities decreased by 35%, or $150 million, in 2011 compared with 2010, as a result of a decrease in capital expenditures of $150 million primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011.

Financing Activities

Net cash used in financing activities was $30 million in 2012 compared with net cash provided by financing activities of $137 million in 2011, primarily as a result of less long-term debt issuances and higher dividends to LKE.

In 2012, cash used in financing activities consisted of:

·the payment of common stock dividends to LKE of $100 million; partially offset by
·the issuance of short-term debt in the form of commercial paper $70 million.

Net cash used in financing activities was $137 million in 2011 compared with net cash provided by financing activities of $56 million in 2010, primarily as a result of less long-term debt issuances and higher dividends to LKE.

In 2011, cash used in financing activities consisted of:

·the payment of common stock dividends to LKE of $124 million;
·a net decrease in notes payable with affiliates of $10 million; and
·the payment of debt issuance and credit facility costs of $3 million.

In the two months of 2010 following the acquisition, cash provided by financing activities of the Successor consisted of:

·the issuance of first mortgage bonds of $1,489 million after discounts; and
·the issuance of debt of $1,331 million to a PPL affiliate to repay debt due to an E.ON AG affiliate upon the closing of PPL's acquisition of LKE; partially offset by
·the repayment of debt to an E.ON AG affiliate of $1,331 million upon the closing of PPL's acquisition of LKE;
·the repayment of debt to a PPL affiliate of $1,331 million upon the issuance of first mortgage bonds;
·a net decrease in notes payable with affiliates of $83 million; and
·the payment of debt issuance and credit facility costs of $17 million.

In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:

·the payment of common stock dividends to LKE of $50 million; partially offset by
·a net increase in notes payable with affiliates of $48 million.

See "Forecasted Sources of Cash" for a discussion of KU's plans to issue debt securities, as well as a discussion of credit facility capacity available to KU.  Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.

KU had no long-term debt securities activity during the year.

See Note 7 to the Financial Statements for additional information about long-term debt securities.
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Auction Rate Securities

At December 31, 2012, KU's tax-exempt revenue bonds that are in the form of auction rate securities and total $96 million continue to experience failed auctions.  Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures.  For the period ended December 31, 2012, the weighted-average rate on KU's auction rate bonds in total was 0.25%.

Forecasted Sources of Cash

KU expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper program, issuance of debt securities and operating cash flow.

Credit Facilities

At December 31, 2012, KU's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:

     Commercial Letters of Unused
   Capacity Paper Issued Credit Issued Capacity
          
Syndicated Credit Facility (a) (d) $ 400  $  70     $ 330 
Letter of Credit Facility (b) (d)   198     $ 198    
 Total Credit Facilities (c) $ 598  $  70  $ 198  $ 330 

(a)In November 2012, KU amended its Syndicated Credit Facility to extend the expiration date to November 2017.
(b)In August 2012, the KU letter of credit facility agreement was amended and restated to allow for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.
(c)The commitments under KU's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 19% of the total committed capacity available to KU.
(d)KU pays customary fees under its syndicated credit facility as well as its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.

KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to $500 million at an interest rate based on a market index of commercial paper issues.  At December 31, 2012 there was no balance outstanding.

See Note 7 to the Financial Statements for further discussion of KU's credit facilities.

Operating Leases

KU also has available funding sources that are provided through operating leases.  KU leases office space and certain equipment.  These leasing structures provide KU additional operating and financing flexibility.  The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.

See Note 11 to the Financial Statements for further discussion of the operating leases.

Capital Contributions from LKE

From time to time LKE may make capital contributions to KU.  KU may use these contributions to fund capital expenditures and for other general corporate purposes.

Long-term Debt Securities

KU currently plans to issue, subject to market conditions, up to $300 million of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.

Forecasted Uses of Cash

In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, KU currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of debt securities.

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Capital Expenditures

The table below shows KU's current capital expenditure projections for the years 2013 through 2017.

    Projected
    2013  2014  2015  2016  2017 
Capital expenditures (a)               
 Generating facilities $ 289  $ 140  $ 136  $ 251  $ 308 
 Distribution facilities   89    87    97    92    107 
 Transmission facilities   48    37    40    40    61 
 Environmental   331    386    264    106    65 
 Other   27    24    25    27    22 
  Total Capital Expenditures $ 784  $ 674  $ 562  $ 516  $ 563 

(a)KU generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates.  The 2013 total excludes amounts included in accounts payable as of December 31, 2012.

KU's capital expenditure projections for the years 2013 through 2017 total approximately $3.1 billion.  Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions.  This table includes current estimates for KU's environmental projects related to existing and proposed EPA compliance standards.  Actual costs may be significantly lower or higher depending on the final requirements and market conditions.  Environmental compliance costs incurred by KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.

KU plans to fund its capital expenditures in 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.

Contractual Obligations

KU has assumed various financial obligations and commitments in the ordinary course of conducting its business.  At December 31, 2012, the estimated contractual cash obligations of KU were:

    Total 2013  2014 - 2015 2016 - 2017 After 2017
                  
Long-term Debt (a) $ 1,851     $ 250     $ 1,601 
Interest on Long-term Debt (b)   1,481  $ 64    130  $ 126    1,161 
Operating Leases (c)   51    9    15    9    18 
Coal and Natural Gas Purchase               
  Obligations (d)   1,046    411    479    156   - 
Unconditional Power Purchase               
  Obligations (e)   319    9    18    20    272 
Construction Obligations (f)   1,023    455    366    202    
Pension Benefit Plan Obligations (g) 59    59          
Other Obligations (h)   21    5    9    6    1 
Total Contractual Cash Obligations $ 5,851  $ 1,012  $ 1,267  $ 519  $ 3,053 

(a)Reflects principal maturities only based on stated maturity dates.  See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of KU.  KU has no capital lease obligations.
(b)Assumes interest payments through stated maturity.  The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated.
(c)See Note 11 to the Financial Statements for additional information.
(d)Represents contracts to purchase coal, natural gas and natural gas transportation.  See Note 15 to the Financial Statements for additional information.
(e)Represents future minimum payments under OVEC power purchase agreements through June 2040.  See Note 15 to the Financial Statements for additional information.
(f)Represents construction commitments, including commitments for the Ghent environmental air projects, Cane Run Unit 7 and Ghent landfill which are also reflected in the Capital Expenditures table presented above.
(g)Based on the current funded status of LKE's qualified pension plan, which covers KU employees, no cash contributions are required.  See Note 13 to the Financial Statements for a discussion of expected contributions.
(h)Represents other contractual obligations.

Dividends

From time to time, as determined by its Board of Directors, KU pays dividends to its sole shareholder, LKE.

As discussed in Note 7 to the Financial Statements, KU's ability to pay dividends is limited under a covenant in its $400 million revolving line of credit facility.  This covenant restricts the debt to total capital ratio to not more than 70%.  See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for KU.

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Purchase or Redemption of Debt Securities

KU will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.

Rating Agency Actions

Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of KU.  Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.

A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues.  The credit ratings of KU are based on information provided by KU and other sources.  The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of KU.  Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities.  The credit ratings of KU affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.

The following table sets forth KU's security credit ratings as of December 31, 2012.

Senior UnsecuredSenior SecuredCommercial Paper
IssuerMoody'sS&PFitchMoody'sS&PFitchMoody'sS&PFitch
Kentucky UtilitiesAA2A-A+P-2A-2F-2

In addition to the credit ratings noted above, the rating agencies took the following actions related to KU:

In February 2012, Fitch assigned ratings to KU's newly established commercial paper program.

In March 2012, Moody's affirmed the following ratings:
·     the long-term ratings of the First Mortgage Bonds for KU;
·     the issuer ratings for KU; and
·     the bank loan ratings for KU.

Also in March 2012, Moody's and S&P each assigned short-term ratings to KU's newly established commercial paper program.

In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlook for KU.

Ratings Triggers

KU has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, and commodity transportation and storage, which contain provisions requiring KU to post additional collateral, or permitting the counterparty to terminate the contract, if KU's credit rating were to fall below investment grade.  See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012.  At December 31, 2012, if KU's credit ratings had been below investment grade, the maximum amount that KU would have been required to post as additional collateral to counterparties was $21 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations.

Off-Balance Sheet Arrangements

KU has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party.  See Note 15 to the Financial Statements for a discussion of these agreements.

Risk Management

Market Risk

See Notes 1, 18 and 19 to the Financial Statements for information about KU's risk management objectives, valuation techniques and accounting designations.

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The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions.  Actual future results may differ materially from those presented.  These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.

Commodity Price Risk (Non-trading)

KU's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers.  As a result, KU is subject to commodity price risk for only a small portion of on-going business operations.  KU sells excess economic generation to maximize the value of the physical assets at times when the assets are not required to serve KU's or LG&E's customers.  See Note 19 to the Financial Statements for additional disclosures.

The balance and change in net fair value of KU's commodity derivative contracts for the periods ended December 31, 2012, 2011 and 2010 were not significant.

Interest Rate Risk

KU issues debt to finance its operations, which exposes it to interest rate risk.  KU utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate.  Risk limits under KU's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of KU's debt portfolio due to changes in the absolute level of interest rates.

At December 31, 2012 and 2011, KU's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.

KU is also exposed to changes in the fair value of its debt portfolio.  KU estimated that a 10% decrease in interest rates at December 31, 2012, would increase the fair value of its debt portfolio by $67 million compared with $72 million at December 31, 2011.

At December 31, 2012, KU had the following interest rate hedges outstanding:
           
       Effect of a
     Fair Value, 10% Adverse
    Exposure Net - Asset Movement
   Hedged (Liability) in Rates
Cash flow hedges         
 Interest rate swaps (a) $ 150  $ 7  $ (9)

(a)KU utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments.  These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing.  While KU is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such cash flow hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities.  Sensitivities represent a 10% adverse movement in interest rates.  The positions outstanding at December 31, 2012 mature through 2043.

Credit Risk

KU is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations.  KU maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds.  KU is exposed to potential losses as a result of nonpayment by customers.  KU maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers.  Allowances for doubtful accounts from wholesale and municipal customers and miscellaneous receivables are based on specific identification by management.  Retail, wholesale and municipal customer accounts are written-off after four months of no payment activity.  Miscellaneous receivables are written-off as management determines them to be uncollectible.

Certain of KU's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon KU's credit ratings from each of the major credit rating agencies.  See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
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Related Party Transactions

KU is not aware of any material ownership interest or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with KU.  See Note 16 to the Financial Statements for additional information on related party transactions.

Environmental Matters

Protection of the environment is a major priority for KU and a significant element of its business activities.  Extensive federal, state and local environmental laws and regulations are applicable to KU's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material.  In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies.  Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions.  Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for KU's services.

Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to KU's generation assets and electricity transmission and distribution systems, as well as impacts on customers.  In addition, changed weather patterns could potentially reduce annual rainfall in areas where KU has hydro generating facilities or where river water is used to cool its fossil powered generators.  KU cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.

See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.

New Accounting Guidance

See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.

Application of Critical Accounting Policies

Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies.  The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain.  Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements).  KU's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.

Revenue Recognition - Unbilled Revenue

Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers.  Because customers of KU's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric meters, KU records estimates for unbilled revenues at the end of each reporting period.  Such unbilled revenue amounts reflect estimates of the amount of electricity delivered to customers since the date of the last reading of their meters.  The unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather, and where applicable, the impact of weather normalization or other regulatory provisions of rate structures.  In addition to the unbilled revenue accrual resulting from cycle billing, KU makes additional accruals resulting from the timing of customer bills.  The accrual of unbilled revenues in this manner properly matches revenues and related costs.  At December 31, 2012 and 2011, KU had unbilled revenue balances of $84 million and $81 million.
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Defined Benefits

KU participates in a qualified funded defined benefit pension plan and a funded other postretirement benefit plan.  These plans are applicable to the majority of the employees of KU and are sponsored by LKE.  LKE allocates a portion of the liability and net periodic defined benefit pension and other postretirement costs of the plans to KU based on its participation.  KU records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets or liabilities.  Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets.  See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.

Certain assumptions are made by LKE regarding the valuation of benefit obligations and the performance of plan assets.  When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle.  Annual net periodic defined benefit costs are recorded in current earnings based on estimated results.  Any differences between actual and estimated results are recorded in regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates.  These amounts in regulatory assets and liabilities are amortized to income over future periods.  The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans.  The primary assumptions are:

·Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future.  The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.

·Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  These projected returns reduce the net benefit costs KU records currently.

·Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.

·Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.

In selecting a discount rate for its defined benefit plans, LKE starts with a cash flow analysis of the expected benefit payment stream for its plans.  The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds.  This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds.  Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed.  At December 31, 2012, LKE decreased the discount rate for its pension plan from 5.12% to 4.26% and decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.

The expected long-term rates of return for LKE's defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class.  LKE management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific asset allocation is also considered in developing a reasonable return assumption.  At December 31, 2012, LKE's expected return on plan assets decreased from 7.25% to 7.10%.

In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates.  At December 31, 2012, LKE's rate of compensation increase remained at 4.00%.

In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs.  At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
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A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities allocated to KU.  While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for KU by a similar amount in the opposite direction.  The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.

At December 31, 2012, the defined benefit plans were recorded as follows:

Pension liabilities$ 104 
Other postretirement benefit liabilities 53 

The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on KU's primary defined benefit plans.

  Increase (Decrease)
     Impact on    Impact on
  Change in defined benefit Impact on regulatory
Actuarial assumption assumption liabilities OCI assets
             
Discount Rate  (0.25)% $ 17     $ 17 
Rate of Compensation Increase  0.25%   3       3 
Health Care Cost Trend Rate (a)  1%   3       3 

(a)Only impacts other postretirement benefits.

In 2012 KU recognized net periodic defined benefit costs charged to operating expense of $11 million.  This amount represents a $3 million decrease from 2011.  This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $15 million, a reduction in the amortization of outstanding losses and lower interest cost.

The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on KU's primary defined benefit plans.

Actuarial assumption  Change in assumption  Impact on defined benefit costs
       
Discount Rate  (0.25)% $ 2 
Expected Return on Plan Assets  (0.25)%   1 
Rate of Compensation Increase  0.25%   1 
Health Care Cost Trend Rate (a)  1%   

(a)Only impacts other postretirement benefits.

Asset Impairment (Excluding Investments)

Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable.  For these long-lived assets classified as held and used, such events or changes in circumstances are:

·a significant decrease in the market price of an asset;
·a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
·a significant adverse change in legal factors or in the business climate;
·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
·a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
·a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
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For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value.  The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset.  If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value.  Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets.  Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome.  If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives.  For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets.  That assessment is not revised based on events that occur after the balance sheet date.  Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.

For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell.  If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell.  A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.

For determining fair value, quoted market prices in active markets are the best evidence.  However, when market prices are unavailable, KU considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained.  Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available.  Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.

Goodwill is tested for impairment at the reporting unit level.  KU's reporting unit has been determined to be at the operating segment level.  A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value.  Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.

Beginning in 2012, KU may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test.  If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary.  However, the quantitative impairment test is required if KU concludes it is more likely than not the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.

When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, KU identifies a potential impairment by comparing the estimated fair value of KU (the goodwill reporting unit) with its carrying amount, including goodwill, on the measurement date.  If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired.  If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.

The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination.  That is, the estimated fair value is allocated to all of KU's assets and liabilities as if KU had been acquired in a business combination and the estimated fair value of KU was the price paid.  The excess of the estimated fair value of KU over the amounts assigned to its assets and liabilities is the implied fair value of goodwill.  The implied fair value of KU's goodwill is then compared with the carrying amount of that goodwill.  If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess.  The loss recognized cannot exceed the carrying amount of KU's goodwill.

KU elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 and no impairment was recognized.  Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of KU.  Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
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Loss Accruals

Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes.  For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated.  Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured.  Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.

The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient.  All three of these aspects require significant judgment by management.  Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.

In 2012, no significant adjustments were made to KU's existing contingencies.

Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual.  Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred.  Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur."

When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable.  The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated.  The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:

·Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected.

·Environmental and other litigation contingencies are reduced when the contingency is resolved, KU makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable.

Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate.  This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.

See Note 15 to the Financial Statements for additional information.

Asset Retirement Obligations

KU is required to recognize a liability for legal obligations associated with the retirement of long-lived assets.  The initial obligation is measured at its estimated fair value.  An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset.  Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statements of Income, for changes in the obligation due to the passage of time.  Since costs of removal are collected in rates, the accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact.  The regulatory asset created by the regulatory credit is relieved when the ARO has been settled.  An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated.  See Note 21 to the Financial Statements for related disclosures.

In determining AROs, management must make significant judgments and estimates to calculate fair value.  Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred.  Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements.  Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations.  Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.

At December 31, 2012, KU had AROs totaling $69 million recorded on the Balance Sheet.  Of the total amount, $51 million, or 74%, relates to KU's ash ponds and landfill.  The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates.  A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.

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The following chart reflects the sensitivities related to KU's ARO liabilities for ash ponds and landfill at December 31, 2012:

  Change in Impact on
  Assumption ARO Liability
       
Retirement Cost  10% $6
Discount Rate  (0.25)%  2
Inflation Rate  0.25%  3

Income Taxes

Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position.  Tax positions are evaluated following a two-step process.  The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained.  This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position.  The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion.  The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%.  Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.

On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date.  Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured.  The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.

At December 31, 2012, KU's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million.  This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.

The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment.  Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date.  Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset.  Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies.  Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position.  See Note 5 to the Financial Statements for related disclosures.

Regulatory Assets and Liabilities

KU is a cost-based rate-regulated utility.  As a result, the effects of regulatory actions are required to be reflected in the financial statements.  Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities.  Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates.  Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.  In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.  The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC, the KPSC, the VSCC or the TRA.
192
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation.  Based on this continual assessment, management believes the existing regulatory assets are probable of recovery.  This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future.  If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income.  Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.

At December 31, 2012, KU had regulatory assets of $230 million and regulatory liabilities of $536 million.  All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.

See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.

Other Information

PPL's Audit Committee has approved the independent auditor to provide audit, tax and other services permitted by Sarbanes-Oxley and SEC rules.  The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.  See "Item 14. Principal Accounting Fees and Services" for more information.


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PPLTalen Energy Corporation PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Reference is made to "Risk Management - Energy Marketing & Trading and Other" for PPL and PPL Energy Supply and "Risk Management" for PPL Electric, LKE, LG&E and KUthe Registrants in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations."


62
194



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Report of Independent Registered Public Accounting Firm

To theThe Board of Directors and ShareownersStockholders of PPLTalen Energy Corporation

We have audited the accompanying consolidated balance sheets of PPLTalen Energy Corporation and subsidiaries as of December 31, 20122015 and 2011,2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012.2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We did not audit the 2010 financial statements of LG&E and KU Energy LLC (LKE), a wholly owned subsidiary, which statements reflect total revenues of $494 million for the period November 1, 2010 (date of acquisition) to December 31, 2010. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for LKE, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includesstatements, assessing the accounting principles used and significant estimates made by management, as well asand evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and, for 2010, the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPLTalen Energy Corporation and subsidiaries at December 31, 20122015 and 2011,2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), PPL Corporation's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP


Philadelphia, Pennsylvania
February 28, 201326, 2016

63
196


Report of Independent Registered Public Accounting Firm

To theThe Board of DirectorsManagers and ShareownersSole Member of PPL CorporationTalen Energy Supply, LLC

We have audited PPL Corporation's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). PPL Corporation's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in Management's Report on Internal Control over Financial Reporting at Item 9A. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, PPL Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012 based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), theaccompanying consolidated balance sheets of Talen Energy Supply, LLC (formerly known as PPL CorporationEnergy Supply, LLC) and subsidiaries as of December 31, 20122015 and 2011,2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012 and our report dated February 28, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP


Philadelphia, Pennsylvania
February 28, 2013

197


Report of Independent Registered Public Accounting Firm

To the Board of Managers and Sole Member of PPL Energy Supply, LLC

We have audited the accompanying consolidated balance sheets of PPL Energy Supply, LLC and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012.2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPLTalen Energy Supply, LLC and subsidiaries at December 31, 20122015 and 2011,2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2015, in conformity with U.S. generally accepted accounting principles.

/s/Ernst & Young LLP


Philadelphia, Pennsylvania
February 28, 201326, 2016


64
198


Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareowners of PPL Electric Utilities Corporation

We have audited the accompanying consolidated balance sheets of PPL Electric Utilities Corporation and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, shareowners' equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPL Electric Utilities Corporation and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP


Philadelphia, Pennsylvania
February 28, 2013

199


Report of Independent Registered Public Accounting Firm

To the Board of Directors and Sole Member of LG&E and KU Energy LLC

We have audited the accompanying consolidated balance sheets of LG&E and KU Energy LLC and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of LG&E and KU Energy LLC and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP


Louisville, Kentucky
February 28, 2013

200


Report of Independent Registered Public Accounting Firm

To the Member of LG&E and KU Energy LLC

In our opinion, the accompanying consolidated statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of LG&E and KU Energy LLC and its subsidiaries (Successor Company) for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 10 to the consolidated financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries.  The push-down basis of accounting was used at the acquisition date.


/s/ PricewaterhouseCoopers LLP


Louisville, Kentucky
February 25, 2011

201


Report of Independent Registered Public Accounting Firm

To the Member of LG&E and KU Energy LLC

In our opinion, the accompanying consolidated statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of LG&E and KU Energy LLC and its subsidiaries (formerly E.ON U.S. LLC, Predecessor Company) for the period from January 1, 2010 to October 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  These financial statements and financial statement schedule are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 10 to the consolidated financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries.  The push-down basis of accounting was used at the acquisition date.


/s/ PricewaterhouseCoopers LLP


Louisville, Kentucky
February 25, 2011

202


Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of Louisville Gas and Electric Company

We have audited the accompanying balance sheets of Louisville Gas and Electric Company as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP


Louisville, Kentucky(THIS PAGE LEFT BLANK INTENTIONALLY)
February 28, 2013

65
203


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm

To the Stockholder of Louisville Gas and Electric Company

In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Louisville Gas and Electric Company (Successor Company) for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries.  The push-down basis of accounting was used at the acquisition date.


/s/ PricewaterhouseCoopers LLP


Louisville, Kentucky
February 25, 2011

204


Report of Independent Registered Public Accounting Firm

To the Stockholder of Louisville Gas and Electric Company

In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Louisville Gas and Electric Company (Predecessor Company) for the period from January 1, 2010 to October 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries.  The push-down basis of accounting was used at the acquisition date.


/s/ PricewaterhouseCoopers LLP


Louisville, Kentucky
February 25, 2011

205


Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of Kentucky Utilities Company

We have audited the accompanying balance sheets of Kentucky Utilities Company as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kentucky Utilities Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP


Louisville, Kentucky
February 28, 2013

206


Report of Independent Registered Public Accounting Firm

To the Stockholder of Kentucky Utilities Company

In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Kentucky Utilities Company (Successor Company) for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries.  The push-down basis of accounting was used at the acquisition date.


/s/ PricewaterhouseCoopers LLP


Louisville, Kentucky
February 25, 2011

207


Report of Independent Registered Public Accounting Firm

To the Stockholder of Kentucky Utilities Company

In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Kentucky Utilities Company (Predecessor Company) for the period from January 1, 2010 to October 31, 2010 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audit.  We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries.  The push-down basis of accounting was used at the acquisition date.


/s/ PricewaterhouseCoopers LLP


Louisville, Kentucky
February 25, 2011

208
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, except share data)
            
     2012  2011  2010 
Operating Revenues      
 
Utility
 $ 6,808  $ 6,292  $ 3,668 
 
Unregulated retail electric and gas
   844    726    415 
 Wholesale energy marketing         
  
Realized
   4,433    3,807    4,832 
  
Unrealized economic activity (Note 19)
   (311)   1,407    (805)
 
Net energy trading margins
   4    (2)   2 
 
Energy-related businesses
   508    507    409 
 
Total Operating Revenues
   12,286    12,737    8,521 
          
Operating Expenses         
 Operation         
  
Fuel
   1,837    1,946    1,235 
  Energy purchases         
   
Realized
   2,997    2,130    2,773 
   
Unrealized economic activity (Note 19)
   (442)   1,123    (286)
  
Other operation and maintenance
   2,835    2,667    1,756 
 
Depreciation
   1,100    960    556 
 
Taxes, other than income
   366    326    238 
 
Energy-related businesses
   484    484    383 
 
Total Operating Expenses
   9,177    9,636    6,655 
             
Operating Income
   3,109    3,101    1,866 
             
Other Income (Expense) - net
   (39)   4    (31)
          
Other-Than-Temporary Impairments
   27    6    3 
             
Interest Expense
   961    898    593 
             
Income from Continuing Operations Before Income Taxes
   2,082    2,201    1,239 
             
Income Taxes
   545    691    263 
             
Income from Continuing Operations After Income Taxes
   1,537    1,510    976 
             
Income (Loss) from Discontinued Operations (net of income taxes)
   (6)   2    (17)
             
Net Income
   1,531    1,512    959 
             
Net Income Attributable to Noncontrolling Interests
   5    17    21 
             
Net Income Attributable to PPL Shareowners
 $ 1,526  $ 1,495  $ 938 
             
Amounts Attributable to PPL Shareowners:         
 
Income from Continuing Operations After Income Taxes
 $ 1,532  $ 1,493  $ 955 
 
Income (Loss) from Discontinued Operations (net of income taxes)
   (6)   2    (17)
 
Net Income
 $ 1,526  $ 1,495  $ 938 
             
Earnings Per Share of Common Stock:   
 Income from Continuing Operations After Income Taxes Available to PPL   
 Common Shareowners:         
  
Basic
 $ 2.62  $ 2.70  $ 2.21 
  
Diluted
 $ 2.61  $ 2.70  $ 2.20 
 Net Income Available to PPL Common Shareowners:         
  
Basic
 $ 2.61  $ 2.71  $ 2.17 
  
Diluted
 $ 2.60  $ 2.70  $ 2.17 
             
Dividends Declared Per Share of Common Stock
 $ 1.44  $ 1.40  $ 1.40 
             
Weighted-Average Shares of Common Stock Outstanding (in thousands)
         
  
Basic
   580,276    550,395    431,345 
  
Diluted
   581,626    550,952    431,569 
             
The accompanying Notes to Financial Statements are an integral part of the financial statements.
209
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
            
    2012  2011  2010 
            
Net income
 $ 1,531  $ 1,512  $ 959 
            
Other comprehensive income (loss):         
Amounts arising during the period - gains (losses), net of tax (expense) benefit:         
 
Foreign currency translation adjustments, net of tax of $2, ($2), ($1)
   94    (48)   (59)
 
Available-for-sale securities, net of tax of ($31), ($6), ($31)
   29    9    29 
 
Qualifying derivatives, net of tax of ($32), ($139), ($148)
   39    202    219 
 
Equity investees' other comprehensive income (loss), net of tax of ($1), $0, $0
   2       
 Defined benefit plans:         
  
Prior service costs, net of tax of $0, ($1), ($14)
   1    (3)   17 
  
Net actuarial gain (loss), net of tax of $343, $58, $50
   (965)   (152)   (80)
  
Transition obligation, net of tax of $0, $0, ($4)
         8 
Reclassifications to net income - (gains) losses, net of tax expense (benefit):         
 
Available-for-sale securities, net of tax of $1, $5, $3
   (7)   (7)   (5)
 
Qualifying derivatives, net of tax of $278, $246, $84
   (434)   (370)   (126)
 
Equity investees' other comprehensive (income) loss, net of tax of $0, $0, $0
      3    
 Defined benefit plans:         
  
Prior service costs, net of tax of ($5), ($5), ($7)
   10    10    12 
  
Net actuarial loss, net of tax of ($29), ($19), ($14)
   79    47    41 
  
Transition obligation, net of tax of $0, $0, ($1)
         2 
Total other comprehensive income (loss) attributable to PPL Shareowners
   (1,152)   (309)   58 
            
Comprehensive income (loss)
   379    1,203    1,017 
 
Comprehensive income attributable to noncontrolling interests
   5    17    21 
            
Comprehensive income (loss) attributable to PPL Shareowners
 $ 374  $ 1,186  $ 996 
            
The accompanying Notes to Financial Statements are an integral part of the financial statements.
210
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars)
     2012  2011  2010 
Cash Flows from Operating Activities         
 
Net income
 $ 1,531  $ 1,512  $ 959 
 Adjustments to reconcile net income to net cash provided by (used in) operating activities         
  
Depreciation
   1,100    961    567 
  
Amortization
   186    254    213 
  
Defined benefit plans - expense
   166    205    102 
  
Deferred income taxes and investment tax credits
   424    582    241 
  
Impairment of assets
   28    13    120 
  
Unrealized (gains) losses on derivatives, and other hedging activities
   27    (314)   542 
  
Provision for Montana hydroelectric litigation
      (74)   66 
  
Other
   52    36    32 
 Change in current assets and current liabilities         
  
Accounts receivable
   7    (89)   (106)
  
Accounts payable
   (29)   (36)   216 
  
Unbilled revenues
   (19)   64    (99)
  
Prepayments
   (5)   294    (318)
  
Counterparty collateral
   (34)   (190)   (18)
  
Taxes
   24    (104)   20 
  
Regulatory assets and liabilities, net
   (2)   106    (110)
  
Accrued interest
   32    109    50 
  
Other
   8    6    9 
 Other operating activities         
  
Defined benefit plans - funding
   (607)   (667)   (396)
  
Other assets
   (33)   (62)   (45)
  
Other liabilities
   (92)   (99)   (12)
   
Net cash provided by (used in) operating activities
   2,764    2,507    2,033 
Cash Flows from Investing Activities         
 
Expenditures for property, plant and equipment
   (3,105)   (2,487)   (1,597)
 
Proceeds from the sale of certain non-core generation facilities
      381    
 
Proceeds from the sale of the Long Island generation business
         124 
 
Proceeds from the sale of the Maine hydroelectric generation business
         38 
 
Ironwood Acquisition, net of cash acquired
   (84)      
 
Acquisition of WPD Midlands
      (5,763)   
 
Acquisition of LKE, net of cash acquired
         (6,812)
 
Purchases of nuclear plant decommissioning trust investments
   (154)   (169)   (128)
 
Proceeds from the sale of nuclear plant decommissioning trust investments
   139    156    114 
 
Proceeds from the sale of other investments
   20    163    
 
Net (increase) decrease in restricted cash and cash equivalents
   96    (143)   85 
 
Other investing activities
   (35)   (90)   (53)
   
Net cash provided by (used in) investing activities
   (3,123)   (7,952)   (8,229)
Cash Flows from Financing Activities         
 
Issuance of long-term debt
   1,223    5,745    4,642 
 
Retirement of long-term debt
   (108)   (1,210)   (20)
 
Issuance of common stock
   72    2,297    2,441 
 
Payment of common stock dividends
   (833)   (746)   (566)
 
Redemption of preference stock of a subsidiary
   (250)      (54)
 
Debt issuance and credit facility costs
   (17)   (102)   (175)
 
Contract adjustment payments on Equity Units
   (94)   (72)   (13)
 
Net increase (decrease) in short-term debt
   74    (125)   70 
 
Other financing activities
   (19)   (20)   (18)
   
Net cash provided by (used in) financing activities
   48    5,767    6,307 
Effect of Exchange Rates on Cash and Cash Equivalents
   10    (45)   13 
Net Increase (Decrease) in Cash and Cash Equivalents
   (301)   277    124 
Cash and Cash Equivalents at Beginning of Period
   1,202    925    801 
Cash and Cash Equivalents at End of Period
 $ 901  $ 1,202  $ 925 
             
Supplemental Disclosures of Cash Flow Information         
 Cash paid (received) during the period for:         
  
Interest - net of amount capitalized
 $ 847  $ 696  $ 458 
  
Income taxes - net
 $ 73  $ (76) $ 313 
             
The accompanying Notes to Financial Statements are an integral part of the financial statements.
211
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
 $ 901  $ 1,202 
 
Short-term investments
      16 
 
Restricted cash and cash equivalents
   54    152 
 Accounts receivable (less reserve:  2012, $64; 2011, $54)      
  
Customer
   745    732 
  
Other
   79    91 
 
Unbilled revenues
   857    834 
 
Fuel, materials and supplies
   673    654 
 
Prepayments
   166    160 
 
Price risk management assets
   1,525    2,548 
 
Regulatory assets
   19    9 
 
Other current assets
   49    28 
 
Total Current Assets
   5,068    6,426 
          
Investments      
 
Nuclear plant decommissioning trust funds
   712    640 
 
Other investments
   47    78 
 
Total Investments
   759    718 
          
Property, Plant and Equipment      
 
Regulated utility plant
   25,196    22,994 
 
Less:  accumulated depreciation - regulated utility plant
   4,164    3,534 
  
Regulated utility plant, net
   21,032    19,460 
 Non-regulated property, plant and equipment      
  
Generation
   11,295    10,514 
  
Nuclear fuel
   524    457 
  
Other
   726    637 
 
Less:  accumulated depreciation - non-regulated property, plant and equipment
   5,942    5,676 
  
Non-regulated property, plant and equipment, net
   6,603    5,932 
 
Construction work in progress
   2,397    1,874 
 
Property, Plant and Equipment, net (a)
   30,032    27,266 
          
Other Noncurrent Assets      
 
Regulatory assets
   1,483    1,349 
 
Goodwill
   4,158    4,114 
 
Other intangibles (a)
   925    1,065 
 
Price risk management assets
   572    920 
 
Other noncurrent assets
   637    790 
 
Total Other Noncurrent Assets
   7,775    8,238 
       
Total Assets
 $ 43,634  $ 42,648 

(a)At December 31, 2012 and December 31, 2011, includes $428 million and $416 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $10 million and $11 million of "Other intangibles" from the consolidation of a VIE that is the owner/lessor of the Lower Mt. Bethel plant.  See Note 22 for additional information.

CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
Talen Energy Corporation and Subsidiaries     
(Millions of Dollars, Except Share Data)     
 2015 2014 2013
Operating Revenues     
Wholesale energy$2,828
 $2,653
 $2,890
Wholesale energy to affiliate14
 84
 51
Retail energy1,095
 1,243
 1,027
Energy-related businesses544
 601
 527
Total Operating Revenues4,481
 4,581
 4,495
Operating Expenses     
Operation     
Fuel1,194
 1,196
 1,048
Energy purchases676
 1,054
 1,153
Operation and maintenance1,052
 1,007
 961
Loss on lease termination—
 —
 697
Impairments657
 —
 65
Depreciation356
 297
 299
Taxes, other than income65
 57
 53
Energy-related businesses520
 573
 512
Total Operating Expenses4,520
 4,184
 4,788
Operating Income (Loss)(39) 397
 (293)
Other Income (Expense) - net(118) 30
 32
Interest Expense211
 124
 159
Income (Loss) from Continuing Operations Before Income Taxes(368) 303
 (420)
Income Taxes(27) 116
 (159)
Income (Loss) from Continuing Operations After Income Taxes(341) 187
 (261)
Income (Loss) from Discontinued Operations (net of income taxes)—
 223
 32
Net Income (Loss)(341) 410
 (229)
Net Income (Loss) Attributable to Noncontrolling Interests—
 —
 1
Net Income (Loss) Attributable to Talen Energy Corporation Stockholders$(341) $410
 $(230)
      
Earnings Per Share of Common Stock Attributable to Talen Energy Corporation Stockholders:     
Basic:     
Income (Loss) from continuing operations after income taxes$(3.10)
$2.24

$(3.13)
Income (Loss) from discontinued operations (net of income taxes)—

2.67

0.38
Net Income (Loss)$(3.10) $4.91
 $(2.75)
Diluted:     
Income (Loss) from continuing operations$(3.10)
$2.24

$(3.13)
Income (Loss) from discontinued operations (net of income taxes)—

2.67

0.38
Net Income (Loss)$(3.10) $4.91
 $(2.75)
      
Weighted-Average Shares of Common Stock Outstanding (in thousands)     
Basic109,898

83,524

83,524
Diluted109,898

83,524

83,524
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.

66
212
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
     2012  2011 
Liabilities and Equity      
          
Current Liabilities      
 
Short-term debt
 $ 652  $ 578 
 
Long-term debt due within one year
   751    
 
Accounts payable
   1,252    1,150 
 
Taxes
   90    65 
 
Interest
   325    287 
 
Dividends
   210    207 
 
Price risk management liabilities
   1,065    1,570 
 
Regulatory liabilities
   61    73 
 
Other current liabilities
   1,219    1,325 
 
Total Current Liabilities
   5,625    5,255 
          
Long-term Debt
   18,725    17,993 
          
Deferred Credits and Other Noncurrent Liabilities      
 
Deferred income taxes
   3,387    3,326 
 
Investment tax credits
   328    285 
 
Price risk management liabilities
   629    840 
 
Accrued pension obligations
   2,076    1,313 
 
Asset retirement obligations
   536    484 
 
Regulatory liabilities
   1,010    1,010 
 
Other deferred credits and noncurrent liabilities
   820    1,046 
 
Total Deferred Credits and Other Noncurrent Liabilities
   8,786    8,304 
          
Commitments and Contingent Liabilities (Notes 6 and 15)      
          
Equity      
 PPL Shareowners' Common Equity      
  
Common stock - $0.01 par value (a)
   6    6 
  
Additional paid-in capital
   6,936    6,813 
  
Earnings reinvested
   5,478    4,797 
  
Accumulated other comprehensive loss
   (1,940)   (788)
  
Total PPL Shareowners' Common Equity
   10,480    10,828 
 
Noncontrolling Interests
   18    268 
 
Total Equity
   10,498    11,096 
          
Total Liabilities and Equity
 $ 43,634  $ 42,648 

(a)780,000 shares authorized; 581,944 and 578,405 shares issued and outstanding at December 31, 2012 and December 31, 2011.
Table of Contents

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31,
Talen Energy Corporation and Subsidiaries
(Millions of Dollars)     
 2015 2014 2013
Net income (loss)$(341) $410
 $(229)
Other comprehensive income (loss):     
Amounts arising during the period - gains (losses), net of tax (expense) benefit:     
Available-for-sale securities, net of tax of $5, ($40), ($72)(6) 35
 67
Defined benefit plans:     
Prior service costs, net of tax of $1, ($6), ($1)(3) 8
 2
Net actuarial gain, net of tax of ($30), $83, ($49)46
 (120) 71
Reclassifications from AOCI - (gains) losses, net of tax expense (benefit):     
Available-for-sale securities, net of tax of $2, $7, $4(2) (6) (6)
Qualifying derivatives, net of tax of $12, $17, $84(19) (25) (123)
Defined benefit plans:     
Prior service costs, net of tax of $0, ($1), ($3)(1) 3
 4
Net actuarial loss, net of tax of $11, ($4), ($10)(18) 5
 14
Total other comprehensive income (loss) attributable to Talen Energy Corporation Stockholders(3) (100) 29
Comprehensive income (loss)(344) 310
 (200)
Comprehensive income attributable to noncontrolling interests—
 —
 1
Comprehensive income (loss) attributable to Talen Energy Corporation Stockholders$(344) $310
 $(201)

The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.


67

CONSOLIDATED STATEMENTS OF EQUITY
PPL Corporation and Subsidiaries
(Millions of Dollars)
 
    PPL Shareowners      
    Common                  
     stock           Accumulated      
    shares     Additional     other  Non-   
    outstanding  Common  paid-in  Earnings  comprehensive  controlling   
    (a)  stock  capital  reinvested  loss  interests  Total
                       
December 31, 2009 (b)
  377,183  $ 4  $ 2,280  $ 3,749  $ (537) $ 319  $ 5,815 
Common stock issued (c)
  106,208    1    2,490             2,491 
Purchase Contracts (d)
        (176)            (176)
Stock-based compensation (e)
        8             8 
Net income
           938       21    959 
Dividends, dividend equivalents,                    
 redemptions and distributions (f)
           (605)      (72)   (677)
Other comprehensive income (loss)
              58       58 
December 31, 2010 (b)
  483,391  $ 5  $ 4,602  $ 4,082  $ (479) $ 268  $ 8,478 
                       
Common stock issued (c)
  95,014  $ 1  $ 2,344           $ 2,345 
Purchase Contracts (d)
        (143)            (143)
Stock-based compensation (e)
        10             10 
Net income
         $ 1,495     $ 17    1,512 
Dividends, dividend equivalents,                    
 redemptions and distributions (f)
           (780)      (17)   (797)
Other comprehensive income (loss)
            $ (309)      (309)
December 31, 2011 (b)
  578,405  $ 6  $ 6,813  $ 4,797  $ (788) $ 268  $ 11,096 
                       
Common stock issued (c)
  3,543     $ 99           $ 99 
Common stock repurchased
  (4)                  
Stock-based compensation (e)
        18             18 
Net income
         $ 1,526     $ 5    1,531 
Dividends, dividend equivalents,                    
 redemptions and distributions (f)
        6    (845)      (255)   (1,094)
Other comprehensive income (loss)
            $ (1,152)      (1,152)
December 31, 2012 (b)
  581,944  $ 6  $ 6,936  $ 5,478  $ (1,940) $ 18  $ 10,498 
      
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
Talen Energy Corporation and Subsidiaries     
(Millions of Dollars)     
 2015
2014
2013
Cash Flows from Operating Activities 
   
Net income (loss)$(341)
$410

$(229)
Adjustments to reconcile net income (loss) to net cash provided by operating activities





 
Pre-tax gain from the sale of Montana hydroelectric generation business—

(315)
—
Depreciation356

313

318
Amortization222

163

156
Defined benefit plans - expense50

42

51
Deferred income taxes and investment tax credits(61)
(26)
(296)
Impairment of assets662

20

65
Unrealized (gains) losses on derivatives, and other hedging activities(119)
4

171
Loss on lease termination—

—

426
Other46

36

2
Change in current assets and current liabilities



 
Accounts receivable115

17

23
Accounts payable(147)
2

(56)
Unbilled revenues58

68

83
Fuel, materials and supplies12

(97)
(31)
Prepayments31

(53)
(5)
Counterparty collateral63

(17)
(81)
Price risk management assets and liabilities(14)
(30)
7
Taxes payable(23)
(3)
(31)
Other(49)
(40)
(16)
Other operating activities     
Defined benefit plans - funding(74)
(35)
(113)
Other assets4

3

(4)
Other liabilities(23)
—

(30)
Net cash provided by operating activities768

462

410
Cash Flows from Investing Activities 
   
Expenditures for property, plant and equipment(451)
(416)
(583)
Proceeds from the sale of Montana hydroelectric generation business—

900

—
Expenditures for intangible assets(70)
(46)
(42)
   Acquisition of MACH Gen(603) —
 —
Purchases of nuclear plant decommissioning trust investments(196)
(170)
(159)
Proceeds from the sale of nuclear plant decommissioning trust investments180

154

144
Proceeds from the sale of the Renewable business116
 —
 —
Proceeds from the receipt of grants—

164

3
Net (increase) decrease in restricted cash and cash equivalents87

(108)
(22)
Other investing activities22

19

28
Net cash provided by (used in) investing activities(915)
497

(631)
Cash Flows from Financing Activities 
   
Issuance of long-term debt600

—

—
Retirement of long-term debt(335)
(309)
(747)
Contributions from predecessor member82

739

1,577
Distributions to predecessor member(217)
(1,906)
(408)
Net increase (decrease) in short-term debt(162)
630

(356)
Other financing activities(32)
—

(19)
Net cash provided by (used in) financing activities(64)
(846)
47
Net Increase (Decrease) in Cash and Cash Equivalents(211)
113

(174)
Cash and Cash Equivalents at Beginning of Period352

239

413
Cash and Cash Equivalents at End of Period$141

$352

$239
Supplemental Disclosures of Cash Flow Information     
Cash paid (received) during the period for:





 
Interest - net of amount capitalized$169

$122

$157
Income taxes - net$5

$310

$189
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.

68

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
Talen Energy Corporation and Subsidiaries


(Millions of Dollars, Shares in Thousands)


 2015
2014
Assets 
 
Current Assets 
 
Cash and cash equivalents$141

$352
Restricted cash and cash equivalents106

176
Accounts receivable (less reserve:  2015, $1; 2014, $2)


Customer205

186
Other62

103
Accounts receivable from affiliates—

36
Unbilled revenues160

218
Fuel, materials and supplies508

455
Prepayments52

70
Price risk management assets562

1,079
Assets held for sale954

—
Other current assets12

26
Total Current Assets2,762

2,701
Investments 
 
Nuclear plant decommissioning trust funds951

950
Other investments25

30
Total Investments976

980
Property, Plant and Equipment 
 
Generation13,468

11,318
Nuclear fuel652

624
Other342

293
Less:  accumulated depreciation6,411

6,242
Property, plant and equipment, net8,051

5,993
Construction work in progress536

443
Total Property, Plant and Equipment, net8,587

6,436
Other Noncurrent Assets 
 
Goodwill—

72
Other intangibles310

257
Price risk management assets131

239
Other noncurrent assets60

75
Total Other Noncurrent Assets501

643
Total Assets$12,826

$10,760

The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.

69

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
Talen Energy Corporation and Subsidiaries


(Millions of Dollars, Shares in Thousands)


 2015
2014
Liabilities and Equity 
 
Current Liabilities 
 
Short-term debt$608
 $630
Long-term debt due within one year399
 535
Accounts payable291
 361
Accounts payable to affiliates—
 50
Taxes16
 28
Interest43
 16
Price risk management liabilities431
 1,024
Liabilities held for sale33
 —
Other current liabilities267
 246
Total Current Liabilities2,088
 2,890
Long-term Debt3,804
 1,683
Deferred Credits and Other Noncurrent Liabilities   
Deferred income taxes1,587
 1,223
Investment tax credits15
 27
Price risk management liabilities108
 193
Accrued pension obligations340
 299
Asset retirement obligations490
 415
Other deferred credits and noncurrent liabilities91
 123
Total Deferred Credits and Other Noncurrent Liabilities2,631
 2,280
Commitments and Contingent Liabilities (Note 11)


Equity




Predecessor Member's Equity (a)—
 3,930
Common Stock - $0.001 par value (b)—
 —
Additional paid-in capital4,702
 —
Accumulated deficit(373) —
Accumulated other comprehensive income (loss)(26) (23)
Total Equity4,303

3,907
Total Liabilities and Equity$12,826

$10,760

(a)Represents Talen Energy Supply's predecessor member's equity prior to the June 1, 2015 spinoff transaction. Upon completion of the spinoff, the predecessor member's equity was transferred to Talen Energy Corporation's additional paid-in capital. See Note 1 for additional information on the spinoff.
(b)1,000,000 shares authorized; 128,509 shares issued and outstanding at December 31, 2015.

The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.


70

CONSOLIDATED STATEMENTS OF EQUITY
Talen Energy Corporation and Subsidiaries
(Millions of Dollars)      
                 
  Common stock shares (a) Common stock Additional paid-in capital Accumulated deficit AOCI Non-controlling interests Predecessor member's equity (b) Total
December 31, 2012 —
 $—
 $—
 $—
 $48
 $18
 $3,782
 $3,848
Net income (loss) —
 —
 —
 —
 —
 1
 (230) (229)
Other comprehensive income (loss) —
 —
 —
 —
 29
 —
 —
 29
Distributions to predecessor member —
 —
 —
 —
 —
 (19) (408) (427)
Contributions from predecessor member —
 —
 —
 —
 —
 —
 1,577
 1,577
December 31, 2013 —
 $—
 $—
 $—
 $77
 $—
 $4,721
 $4,798
                 
Net income (loss) —
 $—
 $—
 $—
 $—
 $—
 $410
 $410
Other comprehensive income (loss) —
 —
 —
 —
 (100) —
 —
 (100)
Distributions to predecessor member —
 —
 —
 —
 —
 —
 (1,940) (1,940)
Contributions from predecessor member —
 —
 —
 —
 —
 —
 739
 739
December 31, 2014 —
 $—
 $—
 $—
 $(23) $—
 $3,930
 $3,907
                 
Net income (loss) from January 1, 2015 to May 31, 2015 —
 $—
 $—
 $—
 $—
 $—
 $32
 $32
Net income (loss) from June 1, 2015 to December 31, 2015 —
 —
 —
 (373) —
 —
 —
 (373)
Other comprehensive income (loss) —
 —
 —
 —
 (3) —
 —
 (3)
Distributions to predecessor member —
 —
 —
 —
 —
 —
 (410) (410)
Contributions from predecessor member —
 —
 —
 —
 —
 —
 248
 248
Common stock issued for acquisition of RJS Power 44,975
 —
 902
 —
 —
 —
 —
 902
Stock issuance 10
 —
 —
 —
 —
 —
 —
 —
Stock issuance expense —
 —
 (2) —
 —
 —
 —
 (2)
Stock-based compensation —
 —
 2
 —
 —
 —
 —
 2
Consummation of spinoff transaction (b) 83,524
 —
 3,800
 —
 —
 —
 (3,800) —
December 31, 2015 128,509

$—

$4,702

$(373)
$(26) $—

$—
 $4,303

(a)Shares in thousands. Each share entitles the holder to one vote on any questionquestions presented at any shareowners'stockholders' meeting.
(b)Upon consummation of the spinoff on June 1, 2015, Talen Energy Supply's predecessor member's equity balance was transferred to Talen Energy Corporation's "Additional paid-in capital." See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
(c)2011 includes the April issuance of 92 million shares of common stock, and 2010 includes the June issuance of 103.5 million shares of common stock.  See Note 7 for additional information.  All years presented include shares of common stock issued through various stock and incentive compensation plans.
(d)2011 includes $123 million for the 2011 Purchase Contracts and $20 million of related fees and expenses, net of tax.  2010 includes $157 million for the 2010 Purchase Contracts and $19 million of related fees and expenses, net of tax.  See Note 7 for additional information.
(e)2012, 2011 and 2010 include $47 million, $33 million and $26 million of stock-based compensation expense related to new and existing unvested equity awards, and $(29) million, $(23) million and $(18) million related primarily to the reclassification from "Stock-based compensation" to "Common stock issued" for the issuance of common stock after applicable equity award vesting periods and tax adjustments related to stock-based compensation.
(f)"Earnings reinvested" includes dividends and dividend equivalents on PPL common stock and restricted stock units.  "Noncontrolling interests" includes dividends, redemptions and distributions to noncontrolling interests.  In April 2010 and June 2012, collectively, PPL Electric redeemed all of its outstanding preferred securities.  See Note 3 for additional information on both redemptions.the spinoff.

The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.

71
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Energy Supply, LLC and Subsidiaries
(Millions of Dollars)
             
     2012  2011  2010 
Operating Revenues         
 Wholesale energy marketing         
  
Realized
 $ 4,433  $ 3,807  $ 4,832 
  
Unrealized economic activity (Note 19)
   (311)   1,407    (805)
 
Wholesale energy marketing to affiliate
   78    26    320 
 
Unregulated retail electric and gas
   848    727    415 
 
Net energy trading margins
   4    (2)   2 
 
Energy-related businesses
   448    464    364 
 
Total Operating Revenues
   5,500    6,429    5,128 
             
Operating Expenses         
 Operation         
  
Fuel
   965    1,080    1,096 
  Energy purchases         
   
Realized
   2,260    1,160    1,636 
   
Unrealized economic activity (Note 19)
   (442)   1,123    (286)
  
Energy purchases from affiliate
   3    3    3 
  
Other operation and maintenance
   1,041    929    979 
 
Depreciation
   285    244    236 
 
Taxes, other than income
   69    71    46 
 
Energy-related businesses
   432    458    357 
 
Total Operating Expenses
   4,613    5,068    4,067 
             
Operating Income
   887    1,361    1,061 
             
Other Income (Expense) - net
   18    23    22 
             
Other-Than-Temporary Impairments
   1    6    3 
             
Interest Income from Affiliates
   2    8    9 
             
Interest Expense
   168    174    208 
             
Income (Loss) from Continuing Operations Before Income Taxes
   738    1,212    881 
             
Income Taxes
   263    445    261 
             
Income (Loss) from Continuing Operations After Income Taxes
   475    767    620 
             
Income (Loss) from Discontinued Operations (net of income taxes)
      2    242 
             
Net Income
   475    769    862 
             
Net Income Attributable to Noncontrolling Interests
   1    1    1 
             
Net Income Attributable to PPL Energy Supply Member
 $ 474  $ 768  $ 861 
             
Amounts Attributable to PPL Energy Supply Member:         
 
Income (Loss) from Continuing Operations After Income Taxes
 $ 474  $ 766  $ 619 
 
Income (Loss) from Discontinued Operations (net of income taxes)
      2    242 
 
Net Income
 $ 474  $ 768  $ 861 
             
The accompanying Notes to Financial Statements are an integral part of the financial statements.

215
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31,
PPL Energy Supply, LLC and Subsidiaries
(Millions of Dollars)
           
    2012  2011  2010 
            
Net income
 $ 475  $ 769  $ 862 
            
Other comprehensive income (loss):         
Amounts arising during the period - gains (losses), net of tax (expense) benefit:         
 
Foreign currency translation adjustments, net of tax of $0, $0, ($1)
         (59)
 
Available-for-sale securities, net of tax of ($31), ($6), ($31)
   29    9    29 
 
Qualifying derivatives, net of tax of ($46), ($164), ($207)
   68    267    305 
 Defined benefit plans:         
  
Prior service costs, net of tax of $0, ($2), ($8)
   1    (2)   12 
  
Net actuarial gain (loss), net of tax of $56, $13, $36
   (82)   (22)   (63)
  
Transition obligation, net of tax of $0, $0, ($3)
         6 
Reclassifications to net income - (gains) losses, net of tax expense (benefit):         
 
Available-for-sale securities, net of tax of $1, $5, $3
   (7)   (7)   (5)
 
Qualifying derivatives, net of tax of $291, $242, $99
   (463)   (353)   (145)
 
Equity investees' other comprehensive (income) loss, net of tax of $0, $0, $0
      3    
 Defined benefit plans:         
  
Prior service costs, net of tax of ($2), ($3), ($5)
   5    4    9 
  
Net actuarial loss, net of tax of ($2), ($2), ($14)
   10    4    39 
  
Transition obligation, net of tax of $0, $0, ($1)
         1 
Total other comprehensive income (loss) attributable to         
 
PPL Energy Supply Member
   (439)   (97)   129 
            
Comprehensive income (loss)
   36    672    991 
 
Comprehensive income attributable to noncontrolling interests
   1    1    1 
            
Comprehensive income (loss) attributable to PPL Energy Supply Member
 $ 35  $ 671  $ 990 
            
The accompanying Notes to Financial Statements are an integral part of the financial statements.

216

CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Energy Supply, LLC and Subsidiaries   
(Millions of Dollars)   
     2012  2011  2010 
Cash Flows from Operating Activities         
 
Net income
 $ 475  $ 769  $ 862 
 Adjustments to reconcile net income to net cash provided by (used in) operating activities         
  
Pre-tax gain from the sale of the Maine hydroelectric generation business
         (25)
  
Depreciation
   285    245    365 
  
Amortization
   119    137    160 
  
Defined benefit plans - expense
   43    36    52 
  
Deferred income taxes and investment tax credits
   152    317    (31)
  
Impairment of assets
   3    13    120 
  
Unrealized (gains) losses on derivatives, and other hedging activities
   (41)   (283)   536 
  
Provision for Montana hydroelectric litigation
      (74)   66 
  
Other
   42    25    41 
 Change in current assets and current liabilities         
  
Accounts receivable
   (54)   38    (18)
  
Accounts payable
   (45)   (89)   20 
  
Unbilled revenues
   33    14    (88)
  
Counterparty collateral
   (34)   (190)   (18)
  
Taxes
   (27)   27    87 
  
Other
   (68)   (18)   8 
 Other operating activities         
  
Defined benefit plans - funding
   (75)   (152)   (302)
  
Other assets
   (41)   (30)   (71)
  
Other liabilities
   17    (9)   76 
   
Net cash provided by (used in) operating activities
   784    776    1,840 
Cash Flows from Investing Activities         
 
Expenditures for property, plant and equipment
   (648)   (661)   (1,009)
 
Proceeds from the sale of certain non-core generation facilities
      381    
 
Proceeds from the sale of the Long Island generation business
         124 
 
Proceeds from the sale of the Maine hydroelectric generation business
         38 
 
Ironwood Acquisition, net of cash acquired
   (84)      
 
Expenditures for intangible assets
   (45)   (57)   (82)
 
Purchases of nuclear plant decommissioning trust investments
   (154)   (169)   (128)
 
Proceeds from the sale of nuclear plant decommissioning trust investments
   139    156    114 
 
Issuance of long-term notes receivable to affiliates
         (1,816)
 
Repayment of long-term notes receivable from affiliates
         1,816 
 
Net (increase) decrease in notes receivable from affiliates
   198    (198)   
 
Net (increase) decrease in restricted cash and cash equivalents
   104    (128)   84 
 
Other investing activities
   21    8    34 
   
Net cash provided by (used in) investing activities
   (469)   (668)   (825)
Cash Flows from Financing Activities         
 
Issuance of long-term debt
      500    602 
 
Retirement of long-term debt
   (9)   (750)   
 
Contributions from member
   563    461    3,625 
 
Distributions to member
   (787)   (316)   (4,692)
 
Cash included in net assets of subsidiary distributed to member
      (325)   
 
Debt issuance and credit facility costs
   (3)   (9)   (53)
 
Net increase (decrease) in short-term debt
   (44)   50    (93)
 
Other financing activities
   (1)   (1)   (1)
   
Net cash provided by (used in) financing activities
   (281)   (390)   (612)
Effect of Exchange Rates on Cash and Cash Equivalents
         13 
Net Increase (Decrease) in Cash and Cash Equivalents
   34    (282)   416 
 
Cash and Cash Equivalents at Beginning of Period
   379    661    245 
 
Cash and Cash Equivalents at End of Period
 $ 413  $ 379  $ 661 
             
Supplemental Disclosures of Cash Flow Information         
 Cash paid (received) during the period for:         
   
Interest - net of amount capitalized
 $ 150  $ 165  $ 275 
   
Income taxes - net
 $ 128  $ 69  $ 278 
             
The accompanying Notes to Financial Statements are an integral part of the financial statements.   
217
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Energy Supply, LLC and Subsidiaries
(Millions of Dollars)
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
 $ 413  $ 379 
 
Restricted cash and cash equivalents
   46    145 
 Accounts receivable (less reserve:  2012, $23; 2011, $15)      
  
Customer
   183    169 
  
Other
   31    31 
 
Accounts receivable from affiliates
   125    89 
 
Unbilled revenues
   369    402 
 
Note receivable from affiliates
      198 
 
Fuel, materials and supplies
   327    298 
 
Prepayments
   15    14 
 
Price risk management assets
   1,511    2,527 
 
Other current assets
   10    11 
 
Total Current Assets
   3,030    4,263 
        
Investments      
 
Nuclear plant decommissioning trust funds
   712    640 
 
Other investments
   41    40 
 
Total Investments
   753    680 
        
Property, Plant and Equipment      
 Non-regulated property, plant and equipment      
  
Generation
   11,305    10,517 
  
Nuclear fuel
   524    457 
  
Other
   294    245 
 
Less:  accumulated depreciation - non-regulated property, plant and equipment
   5,817    5,573 
  
Non-regulated property, plant and equipment, net
   6,306    5,646 
 
Construction work in progress
   987    840 
 
Property, Plant and Equipment, net (a)
   7,293    6,486 
        
Other Noncurrent Assets      
 
Goodwill
   86    86 
 
Other intangibles (a)
   252    386 
 
Price risk management assets
   557    896 
 
Other noncurrent assets
   404    382 
 
Total Other Noncurrent Assets
   1,299    1,750 
        
Total Assets
 $ 12,375  $ 13,179 

(a)At December 31, 2012 and December 31, 2011, includes $428 million and $416 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $10 million and $11 million of "Other intangibles" from the consolidation of a VIE that is the owner/lessor of the Lower Mt. Bethel plant.  See Note 22 for additional information.   
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
Talen Energy Supply, LLC and Subsidiaries     
(Millions of Dollars)     
 2015 2014 2013
Operating Revenues     
Wholesale energy$2,828
 $2,653
 $2,890
Wholesale energy to affiliate14
 84
 51
Retail energy1,095
 1,243
 1,027
Energy-related businesses544
 601
 527
Total Operating Revenues4,481
 4,581
 4,495
Operating Expenses     
Operation     
Fuel1,194
 1,196
 1,048
Energy purchases676
 1,054
 1,153
Operation and maintenance1,052
 1,007
 961
Loss on lease termination—
 —
 697
Impairments657
 —
 65
Depreciation356
 297
 299
Taxes, other than income65
 57
 53
Energy-related businesses520
 573
 512
Total Operating Expenses4,520
 4,184
 4,788
Operating Income (Loss)(39) 397
 (293)
Other Income (Expense) - net(118) 30
 32
Interest Expense211
 124
 159
Income (Loss) from Continuing Operations Before Income Taxes(368) 303
 (420)
Income Taxes(27) 116
 (159)
Income (Loss) from Continuing Operations After Income Taxes(341) 187
 (261)
Income (Loss) from Discontinued Operations (net of income taxes)—
 223
 32
Net Income (Loss)(341) 410
 (229)
Net Income (Loss) Attributable to Noncontrolling Interests—
 —
 1
Net Income (Loss) Attributable to Talen Energy Supply Member$(341) $410
 $(230)
Amounts Attributable to Talen Energy Supply Member:     
Income (Loss) from Continuing Operations After Income Taxes$(341) $187
 $(262)
Income (Loss) from Discontinued Operations (net of income taxes)—
 223
 32
Net Income (Loss)$(341) $410
 $(230)

The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.


72
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Energy Supply, LLC and Subsidiaries
(Millions of Dollars)
      2012   2011 
Liabilities and Equity      
          
Current Liabilities      
 
Short-term debt
 $ 356  $ 400 
 
Long-term debt due within one year
   751    
 
Accounts payable
   438    472 
 
Accounts payable to affiliates
   31    14 
 
Taxes
   62    90 
 
Interest
   31    30 
 
Price risk management liabilities
   1,010    1,560 
 
Deferred income taxes
   158    315 
 
Other current liabilities
   319    344 
 
Total Current Liabilities
   3,156    3,225 
          
Long-term Debt
   2,521    3,024 
       
Deferred Credits and Other Noncurrent Liabilities      
 
Deferred income taxes
   1,232    1,223 
 
Investment tax credits
   186    136 
 
Price risk management liabilities
   556    785 
 
Accrued pension obligations
   293    214 
 
Asset retirement obligations
   365    349 
 
Other deferred credits and noncurrent liabilities
   218    186 
 
Total Deferred Credits and Other Noncurrent Liabilities
   2,850    2,893 
          
Commitments and Contingent Liabilities (Note 15)      
       
Equity      
 
Member's equity
   3,830    4,019 
 
Noncontrolling interests
   18    18 
 
Total Equity
   3,848    4,037 
          
Total Liabilities and Equity
 $ 12,375  $ 13,179 
          
The accompanying Notes to Financial Statements are an integral part of the financial statements.
219

CONSOLIDATED STATEMENTS OF EQUITY
PPL Energy Supply, LLC and Subsidiaries
(Millions of Dollars)
          
     Non-   
  Member's controlling   
  equity interests Total
          
December 31, 2009 (a)
 $ 4,568  $ 18  $ 4,586 
Net income
   861    1    862 
Other comprehensive income (loss)
   129       129 
Contributions from member
   3,625       3,625 
Distributions
   (4,692)   (1)   (4,693)
December 31, 2010 (a)
 $ 4,491  $ 18  $ 4,509 
          
Net income
 $ 768  $ 1  $ 769 
Other comprehensive income (loss)
   (97)      (97)
Contributions from member
   461       461 
Distributions
   (316)   (1)   (317)
Distribution of membership interest in PPL Global (b)
   (1,288)      (1,288)
December 31, 2011 (a)
 $ 4,019  $ 18  $ 4,037 
          
Net income
 $ 474  $ 1  $ 475 
Other comprehensive income (loss)
   (439)      (439)
Contributions from member
   563       563 
Distributions
   (787)   (1)   (788)
December 31, 2012 (a)
 $ 3,830  $ 18  $ 3,848 

(a)See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
(b)See Note 9 for additional information.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31,
Talen Energy Supply, LLC and Subsidiaries
(Millions of Dollars)     
 2015 2014 2015
Net income (loss)$(341) $410
 $(229)
Other comprehensive income (loss):     
Amounts arising during the period - gains (losses), net of tax (expense) benefit:     
Available-for-sale securities, net of tax of $5, ($40), ($72)(6) 35
 67
Defined benefit plans:     
Prior service costs, net of tax of $1, ($6), ($1)(3) 8
 2
Net actuarial gain, net of tax of ($30), $83, ($49)46
 (120) 71
Reclassifications from AOCI - (gains) losses, net of tax expense (benefit):     
Available-for-sale securities, net of tax of $2, $7, $4(2) (6) (6)
Qualifying derivatives, net of tax of $12, $17, $84(19) (25) (123)
Defined benefit plans:     
Prior service costs, net of tax of $0, ($1), ($3)(1) 3
 4
Net actuarial loss, net of tax of $11, ($4), ($10)(18) 5
 14
Total other comprehensive income (loss) attributable to Talen Energy Supply Member(3) (100) 29
Comprehensive income (loss)(344)
310

(200)
Comprehensive income attributable to noncontrolling interests—
 —
 1
Comprehensive income (loss) attributable to Talen Energy Supply Member$(344) $310
 $(201)

The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.


73
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CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
Talen Energy Supply, LLC and Subsidiaries     
(Millions of Dollars)     
 2015 2014 2013
Cash Flows from Operating Activities     
Net income (loss)$(341) $410
 $(229)
  Adjustments to reconcile net income (loss) to net cash provided by operating activities

 

  
Pre-tax gain from the sale of Montana hydroelectric generation business—
 (315) —
Depreciation356
 313
 318
 Amortization222
 163
 156
Defined benefit plans - expense50
 42
 51
Deferred income taxes and investment tax credits(61) (26) (296)
Impairment of assets662
 20
 65
Unrealized (gains) losses on derivatives, and other hedging activities(119) 4
 171
Loss on lease termination—
 —
 426
Other46
 36
 2
Change in current assets and current liabilities
 
  
Accounts receivable115
 17
 23
Accounts payable(147) 2
 (56)
Unbilled revenues58
 68
 83
Fuel, materials and supplies12
 (97) (31)
Prepayments31
 (53) (5)
Counterparty collateral63
 (17) (81)
Price risk management assets and liabilities(14) (30) 7
Taxes payable(23) (3) (31)
Other(49) (40) (16)
Other operating activities     
Defined benefit plans - funding(74) (35) (113)
Other assets4
 3
 (4)
Other liabilities(23) —
 (30)
Net cash provided by operating activities768
 462
 410
Cash Flows from Investing Activities     
Expenditures for property, plant and equipment(451) (416) (583)
Proceeds from the sale of Montana hydroelectric generation business—
 900
 —
Expenditures for intangible assets(70) (46) (42)
   Acquisition of MACH Gen(603) —
 —
Purchases of nuclear plant decommissioning trust investments(196) (170) (159)
Proceeds from the sale of nuclear plant decommissioning trust investments180
 154
 144
Proceeds from the sale of the Renewable business116
 —
 —
Proceeds from the receipt of grants—
 164
 3
Net (increase) decrease in restricted cash and cash equivalents87
 (108) (22)
Other investing activities22
 19
 28
Net cash provided by (used in) investing activities(915) 497
 (631)
Cash Flows from Financing Activities     
Issuance of long-term debt600
 —
 —
Retirement of long-term debt(335) (309) (747)
Contributions from member82
 739
 1,577
Distributions to member(219) (1,906) (408)
Net increase (decrease) in short-term debt(162) 630
 (356)
Other financing activities(30) —
 (19)
Net cash provided by (used in) financing activities(64) (846) 47
Net Increase (Decrease) in Cash and Cash Equivalents(211) 113
 (174)
Cash and Cash Equivalents at Beginning of Period352
 239
 413
Cash and Cash Equivalents at End of Period$141
 $352
 $239
Supplemental Disclosures of Cash Flow Information     
Cash paid (received) during the period for:     
Interest - net of amount capitalized$169
 $122
 $157
Income taxes - net$5
 $310
 $189
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.

74

CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
            
    2012  2011  2010 
Operating Revenues         
 
Retail electric
 $ 1,760  $ 1,881  $ 2,448 
 
Electric revenue from affiliate
   3    11    7 
 
Total Operating Revenues
   1,763    1,892    2,455 
            
Operating Expenses         
 Operation         
  
Energy purchases
   550    738    1,075 
  
Energy purchases from affiliate
   78    26    320 
  
Other operation and maintenance
   576    530    502 
 
Depreciation
   160    146    136 
 
Taxes, other than income
   105    104    138 
 
Total Operating Expenses
   1,469    1,544    2,171 
            
Operating Income
   294    348    284 
            
Other Income (Expense) - net
   9    7    7 
            
Interest Expense
   99    98    99 
            
Income Before Income Taxes
   204    257    192 
            
Income Taxes
   68    68    57 
            
Net Income (a)
   136    189    135 
            
Distributions on Preferred Securities
   4    16    20 
            
Net Income Available to PPL
 $ 132  $ 173  $ 115 

(a)Net income approximates comprehensive income.
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
Talen Energy Supply, LLC and Subsidiaries   
(Millions of Dollars)   
 2015 2014
Assets   
Current Assets   
Cash and cash equivalents$141
 $352
Restricted cash and cash equivalents106
 176
Accounts receivable (less reserve:  2015, $1; 2014, $2)
 
Customer205
 186
Other62
 103
Accounts receivable from affiliates—
 36
Unbilled revenues160
 218
Fuel, materials and supplies508
 455
Prepayments52
 70
Price risk management assets562
 1,079
Assets held for sale954
 —
Other current assets12
 26
Total Current Assets2,762
 2,701
Investments   
Nuclear plant decommissioning trust funds951
 950
Other investments25
 30
Total Investments976
 980
Property, Plant and Equipment   
Generation13,468
 11,318
Nuclear fuel652
 624
Other342
 293
Less:  accumulated depreciation6,411
 6,242
Property, plant and equipment, net8,051
 5,993
Construction work in progress536
 443
Total Property, Plant and Equipment, net8,587
 6,436
Other Noncurrent Assets   
Goodwill—
 72
Other intangibles310
 257
Price risk management assets131
 239
Other noncurrent assets60
 75
Total Other Noncurrent Assets501
 643
Total Assets$12,826
 $10,760

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.
222
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
     2012  2011  2010 
Cash Flows from Operating Activities         
 
Net income
 $ 136  $ 189  $ 135 
 Adjustments to reconcile net income to net cash provided by (used in) operating activities         
  
Depreciation
   160    146    136 
  
Amortization
   18    8    (23)
  
Defined benefit plans - expense
   22    18    20 
  
Deferred income taxes and investment tax credits
   114    106    198 
  
Other
   2    1    4 
 Change in current assets and current liabilities         
  
Accounts receivable
   3    (5)   (38)
  
Accounts payable
   27    (68)   31 
  
Unbilled revenues
   (8)   36    59 
  
Prepayments
   2    58    (112)
  
Regulatory assets and liabilities
   (1)   107    (85)
  
Taxes
   12    (23)   (38)
  
Other
   (5)   7    (27)
 Other operating activities         
  
Defined benefit plans - funding
   (59)   (113)   (55)
  
Other assets
   (3)   (28)   5 
  
Other liabilities
   (31)   (19)   2 
   
Net cash provided by (used in) operating activities
   389    420    212 
             
Cash Flows from Investing Activities         
 
Expenditures for property, plant and equipment
   (624)   (481)   (401)
 
Other investing activities
   11    4    (2)
   
Net cash provided by (used in) investing activities
   (613)   (477)   (403)
             
Cash Flows from Financing Activities         
 
Issuance of long-term debt
   249    645    
 
Retirement of long-term debt
      (458)   
 
Contributions from PPL
   150    100    55 
 
Redemption of preference stock
   (250)      (54)
 
Payment of common stock dividends to parent
   (95)   (92)   (71)
 
Other financing activities
   (10)   (22)   (20)
   
Net cash provided by (used in) financing activities
   44    173    (90)
             
Net Increase (Decrease) in Cash and Cash Equivalents
   (180)   116    (281)
Cash and Cash Equivalents at Beginning of Period
   320    204    485 
Cash and Cash Equivalents at End of Period
 $ 140  $ 320  $ 204 
             
Supplemental Disclosures of Cash Flow Information         
 Cash paid (received) during the period for:         
   
Interest - net of amount capitalized
 $ 81  $ 75  $ 87 
   
Income taxes - net
 $ (42) $ (44) $ (33)
             
The accompanying Notes to Financial Statements are an integral part of the financial statements.
223
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
 $ 140  $ 320 
 Accounts receivable (less reserve: 2012, $18; 2011, $17)      
  
Customer
   249    267 
  
Other
   5    9 
 
Accounts receivable from affiliates
   29    35 
 
Unbilled revenues
   110    102 
 
Materials and supplies
   39    42 
 
Prepayments
   76    78 
 
Deferred income taxes
   45    25 
 
Other current assets
   4    5 
 
Total Current Assets
   697    883 
          
Property, Plant and Equipment      
 
Regulated utility plant
   6,286    5,830 
 
Less: accumulated depreciation - regulated utility plant
   2,316    2,217 
  
Regulated utility plant, net
   3,970    3,613 
 
Other, net
   2    2 
 
Construction work in progress
   370    242 
 
Property, Plant and Equipment, net
   4,342    3,857 
          
Other Noncurrent Assets      
 
Regulatory assets
   853    729 
 
Intangibles
   171    155 
 
Other noncurrent assets
   55    81 
 
Total Other Noncurrent Assets
   1,079    965 
          
Total Assets
 $ 6,118  $ 5,705 
          
The accompanying Notes to Financial Statements are an integral part of the financial statements.
224
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars, shares in thousands)
     2012  2011 
Liabilities and Equity      
          
Current Liabilities      
 
Accounts payable
 $ 259  $ 171 
 
Accounts payable to affiliates
   63    64 
 
Taxes
   12    
 
Interest
   26    24 
 
Regulatory liabilities
   52    53 
 
Customer deposits and prepayments
   21    39 
 
Vacation
   23    22 
 
Other current liabilities
   49    47 
 
Total Current Liabilities
   505    420 
          
Long-term Debt
   1,967    1,718 
          
Deferred Credits and Other Noncurrent Liabilities      
 
Deferred income taxes
   1,233    1,115 
 
Investment tax credits
   3    5 
 
Accrued pension obligations
   237    186 
 
Regulatory liabilities
   8    7 
 
Other deferred credits and noncurrent liabilities
   103    129 
 
Total Deferred Credits and Other Noncurrent Liabilities
   1,584    1,442 
          
Commitments and Contingent Liabilities (Notes 6 and 15)      
          
Shareowners' Equity      
 
Preferred securities
      250 
 
Common stock - no par value (a)
   364    364 
 
Additional paid-in capital
   1,135    979 
 
Earnings reinvested
   563    532 
 
Total Equity
   2,062    2,125 
          
Total Liabilities and Equity
 $ 6,118  $ 5,705 


(a)170,000 shares authorized; 66,368 shares issued and outstanding at December 31, 2012 and December 31, 2011.





75

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
Talen Energy Supply, LLC and Subsidiaries   
(Millions of Dollars)   
 2015 2014
Liabilities and Equity   
Current Liabilities   
Short-term debt$608
 $630
Long-term debt due within one year399
 535
Accounts payable291
 361
Accounts payable to affiliates—
 50
Taxes16
 28
Interest43
 16
Price risk management liabilities431
 1,024
Liabilities held for sale33
 —
Other current liabilities267
 246
Total Current Liabilities2,088
 2,890
Long-term Debt3,804
 1,683
Deferred Credits and Other Noncurrent Liabilities   
Deferred income taxes1,587
 1,223
Investment tax credits15
 27
Price risk management liabilities108
 193
Accrued pension obligations340
 299
Asset retirement obligations490
 415
Other deferred credits and noncurrent liabilities91
 123
Total Deferred Credits and Other Noncurrent Liabilities2,631
 2,280
Commitments and Contingent Liabilities (Note 11)
 
Member's Equity4,303
 3,907
Total Liabilities and Equity$12,826
 $10,760

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.

76
225
CONSOLIDATED STATEMENTS OF SHAREOWNERS' EQUITY
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
               
    Common          
    stock          
    shares     Additional    
    outstanding Preferred Common  paid-in Earnings  
     (a) securities  stock  capital  reinvested Total
                    
December 31, 2009
  66,368  $ 301  $ 364  $ 824  $ 407  $ 1,896 
Net income
              135    135 
Redemption of preferred securities (b)
     (51)         (3)   (54)
Capital contributions from PPL
           55       55 
Cash dividends declared on preferred securities
              (17)   (17)
Cash dividends declared on common stock
              (71)   (71)
December 31, 2010
  66,368  $ 250  $ 364  $ 879  $ 451  $ 1,944 
                    
Net income
            $ 189  $ 189 
Capital contributions from PPL
         $ 100       100 
Cash dividends declared on preferred securities
              (16)   (16)
Cash dividends declared on common stock
              (92)   (92)
December 31, 2011
  66,368  $ 250  $ 364  $ 979  $ 532  $ 2,125 
                    
Net income
            $ 136  $ 136 
Redemption of preferred securities (b)
   $ (250)    $ 6    (6)   (250)
Capital contributions from PPL
           150       150 
Cash dividends declared on preferred securities
              (4)   (4)
Cash dividends declared on common stock
              (95)   (95)
December 31, 2012
  66,368  $  $ 364  $ 1,135  $ 563  $ 2,062 

(a)Shares in thousands.  All common shares of PPL Electric stock are owned by PPL.
(b)In April 2010 and June 2012, collectively, PPL Electric redeemed all of its outstanding preferred securities.  See Note 3 for additional information on both redemptions.

The accompanying Notes to Financial Statements are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF INCOME
LG&E and KU Energy LLC and Subsidiaries
(Millions of Dollars)       
                  
     Successor  Predecessor
          Two Months  Ten Months
     Year Ended  Year Ended Ended  Ended
     December 31,  December 31, December 31,  October 31,
     2012   2011  2010   2010
               
Operating Revenues
 $ 2,759   $ 2,793  $ 494   $ 2,214 
               
Operating Expenses              
 Operation              
  
Fuel
   872     866    138     723 
  
Energy purchases
   195     238    68     211 
  
Other operation and maintenance
   778     751    141     586 
 
Depreciation
   346     334    49     235 
 
Taxes, other than income
   46     37    2     21 
 
Total Operating Expenses
   2,237     2,226    398     1,776 
                  
Operating Income
   522     567    96     438 
                  
Other Income (Expense) - net
   (15)    (1)   (2)    14 
               
Other-Than-Temporary Impairments
   25            
                  
Interest Expense
   150     146    20     21 
                  
Interest Expense with Affiliate
   1     1    4     131 
                  
Income (Loss) from Continuing Operations Before Income              
 
Taxes
   331     419    70     300 
                  
Income Taxes
   106     153    25     109 
                  
Income (Loss) from Continuing Operations After Income              
 
Taxes
   225     266    45     191 
                  
Income (Loss) from Discontinued Operations (net of income              
 
taxes)
   (6)    (1)   2     (1)
                  
Net Income (Loss)
 $ 219   $ 265  $ 47   $ 190 
                  
                  
The accompanying Notes to Financial Statements are an integral part of the financial statements.
227
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
LG&E and KU Energy LLC and Subsidiaries
(Millions of Dollars)
                  
      Successor  Predecessor
          Two Months  Ten Months
      Year Ended Year Ended Ended  Ended
      December 31, 
December 31,
 December 31,  October 31,
      2012  2011  2010   2010
                  
Net income (loss)
 $ 219  $ 265  $ 47   $ 190 
                  
Other comprehensive income (loss):             
 Amounts arising during the period - gains (losses), net of tax             
  (expense) benefit:             
   
Qualifying derivatives, net of tax of $0, $0, $0, ($7)
             10 
   Equity investee's other comprehensive income (loss), net             
    
of tax of  ($1), $0, $0, $1
   1           (2)
   Defined benefit plans:             
    
Prior service costs, net of tax of $0, $1, $0, $0
      (2)       
    
Net actuarial loss, net of tax of $13, ($1), ($3), $15
   (21)      6     (20)
 Reclassification to net income - (gains) losses, net of tax             
  expense (benefit):             
   Defined benefit plans:             
    
Prior service costs, net of tax of $0, $0, $0, ($1)
             1 
    
Net actuarial loss, net of tax of $0, $1, $0, ($1)
   1           1 
Total other comprehensive income (loss)
   (19)   (2)   6     (10)
                  
Comprehensive income (loss) attributable to member
 $ 200  $ 263  $ 53   $ 180 
                  
The accompanying Notes to Financial Statements are an integral part of the financial statements.
228

CONSOLIDATED STATEMENTS OF CASH FLOWS
    
LG&E and KU Energy LLC and Subsidiaries    
(Millions of Dollars)    
      Successor  Predecessor
          Two Months  Ten Months
      
Year Ended
 Year Ended Ended  Ended
      December 31, December 31, December 31,  October 31,
      2012  2011  2010   2010 
Cash Flows from Operating Activities             
 
Net income (loss)
 $ 219  $ 265  $ 47   $ 190 
 Adjustments to reconcile net income (loss) to net cash             
  provided by (used in) operating activities             
   
Depreciation
   346    334    49     235 
   
Amortization of regulatory assets
   27    27    3     
   
Defined benefit plans - expense
   40    51    12     52 
   
Deferred income taxes and investment tax credits
   133    218    52     65 
   
Unrealized (gains) losses on derivatives
             14 
   
Loss from discontinued operations - net of tax
             1 
   
Impairment of assets
   25           
   
Other
   2    (9)   11     (23)
 Change in current assets and current liabilities             
  
Accounts receivable
   (9)   17    (17)    12 
  
Accounts payable
   1    (32)   (14)    (34)
  
Accounts payable to affiliates
   (1)      4     (7)
  
Unbilled revenues
   (10)   24    (70)    41 
  
Fuel, materials and supplies
   8    15    15     (28)
  
Income tax receivable
   2    37    (40)    (2)
  
Taxes
   1    (2)   4     18 
  
Other
      (1)   (27)    47 
 Other operating activities             
  
Defined benefit plans - funding
   (70)   (170)   (8)    (57)
  
Discontinued operations
             13 
  
Other assets
   (5)   (11)   12     14 
  
Other liabilities
   38    18    (7)    (63)
   
Net cash provided by (used in) operating activities
   747    781    26     488 
Cash Flows from Investing Activities             
 
Expenditures for property, plant and equipment
   (768)   (477)   (152)    (447)
 
Proceeds from sales of discontinued operations
             21 
 
Proceeds from the sale of other investments
      163        
 
Net (increase) decrease in notes receivable from affiliates
   15    46    (61)    
 
Net (increase) decrease in restricted cash and cash equivalents
   (3)   (9)   2     
   
Net cash provided by (used in) investing activities
   (756)   (277)   (211)    (426)
Cash Flows from Financing Activities             
 
Issuance of short-term debt with affiliate
         1,001     900 
 
Retirement of short-term debt with affiliate
         (1,001)    (575)
 
Net increase (decrease) in notes payable with affiliates
   25           (3)
 
Issuance of long-term debt with affiliate
         1,783     50 
 
Retirement of long-term debt with affiliate
         (1,783)    (325)
 
Issuance of long-term debt
      250    2,890     
 
Retirement of long-term debt
      (2)       
 
Net increase (decrease) in short-term debt
   125    (163)   163     
 
Repayment to E.ON AG affiliates
         (4,319)    
 
Debt issuance and credit facility costs
   (2)   (8)   (32)    
 
Distributions to member
   (155)   (533)   (100)    (87)
 
Contributions from member
         1,565     
   
Net cash provided by (used in) financing activities
   (7)   (456)   167     (40)
Net Increase (Decrease) in Cash and Cash Equivalents
   (16)   48    (18)    22 
Cash and Cash Equivalents at Beginning of Period
   59    11    29     7 
Cash and Cash Equivalents at End of Period
 $ 43  $ 59  $ 11   $ 29 
                  
Supplemental Disclosures of Cash Flow Information             
 Cash paid (received) during the period for:             
  
Interest - net of amount capitalized
 $ 139  $ 126  $ 41   $ 153 
  
Income taxes - net
 $ (45) $ (98) $ (1)  $ 9 
                  
The accompanying Notes to Financial Statements are an integral part of the financial statements.
229

CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
LG&E and KU Energy LLC and Subsidiaries
(Millions of Dollars)
          
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
 $ 43  $ 59 
 Accounts receivable (less reserve: 2012, $19; 2011, $17)      
  
Customer
   133    129 
  
Other
   19    20 
 
Unbilled revenues
   156    146 
 
Accounts receivable from affiliates
   1    
 
Notes receivable from affiliates
      15 
 
Fuel, materials and supplies
   276    283 
 
Prepayments
   28    22 
 
Price risk management assets from affiliates
   14    
 
Income taxes receivable
   1    3 
 
Deferred income taxes
   13    17 
 
Regulatory assets
   19    9 
 
Other current assets
   4    3 
 
Total Current Assets
   707    706 
          
Investments
   1    31 
          
Property, Plant and Equipment      
 
Regulated utility plant
   8,073    7,519 
 
Less: accumulated depreciation - regulated utility plant
   519    277 
  
Regulated utility plant, net
   7,554    7,242 
 
Other, net
   3    2 
 
Construction work in progress
   750    557 
 
Property, Plant and Equipment, net
   8,307    7,801 
          
Other Noncurrent Assets      
 
Regulatory assets
   630    620 
 
Goodwill
   996    996 
 
Other intangibles
   271    314 
 
Other noncurrent assets
   107    108 
 
Total Other Noncurrent Assets
   2,004    2,038 
          
Total Assets
 $ 11,019  $ 10,576 
          
The accompanying Notes to Financial Statements are an integral part of the financial statements.
230
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
LG&E and KU Energy LLC and Subsidiaries
(Millions of Dollars)
     2012  2011 
Liabilities and Equity      
          
Current Liabilities      
 
Short-term debt
 $ 125    
 
Notes payable with affiliates
   25    
 
Accounts payable
   283  $ 224 
 
Accounts payable to affiliates
   1    2 
 
Customer deposits
   48    45 
 
Taxes
   26    25 
 
Regulatory liabilities
   9    20 
 
Interest
   21    23 
 
Salaries and benefits
   69    59 
 
Other current liabilities
   36    35 
 
Total Current Liabilities
   643    433 
          
Long-term Debt
   4,075    4,073 
       
Deferred Credits and Other Noncurrent Liabilities      
 
Deferred income taxes
   541    413 
 
Investment tax credits
   138    144 
 
Price risk management liabilities
   53    55 
 
Accrued pension obligations
   414    359 
 
Asset retirement obligations
   125    116 
 
Regulatory liabilities
   1,002    1,003 
 
Other deferred credits and noncurrent liabilities
   242    239 
 
Total Deferred Credits and Other Noncurrent Liabilities
   2,515    2,329 
          
Commitments and Contingent Liabilities (Notes 6 and 15)      
          
Member's equity
   3,786    3,741 
          
Total Liabilities and Equity
 $ 11,019  $ 10,576 
          
The accompanying Notes to Financial Statements are an integral part of the financial statements.
231
CONSOLIDATED STATEMENTS OF EQUITY
CONSOLIDATED STATEMENTS OF EQUITY
     
LG&E and KU Energy LLC and Subsidiaries
Talen Energy Supply, LLC and Subsidiaries     
(Millions of Dollars)(Millions of Dollars)     
      Member's equity 
Non-
controlling
interests
 Total
   Non-   
 Member's controlling  
 Equity  interests  Total
      
December 31, 2009 - Predecessor (a)
 $ 2,192  $ 32  $ 2,224 
Net income
  190     190 
December 31, 2012$3,830
 $18
 $3,848
Net income (loss)(230) 1
 (229)
Other comprehensive income (loss)29
 —
 29
Distributions to member
  (81)    (81)(408) (19) (427)
Other comprehensive income (loss)
  (10)    (10)
Noncontrolling interest - income (loss) from discontinued operations
   (11)   (32)   (43)
October 31, 2010 - Predecessor (a)
 $ 2,280  $  $ 2,280 
      
      
Effect of PPL acquisition
 $ 213    $ 213 
Net income
  47     47 
Contributions from member
  1,565     1,565 1,577
 —
 1,577
Distributions to member
  (100)    (100)
Other comprehensive income (loss)
   6       6 
December 31, 2010 - Successor (a)
 $ 4,011     $ 4,011 
      
December 31, 2013$4,798
 $—
 $4,798
           
Net income
 $ 265    $ 265 $410
 —
 $410
Other comprehensive income (loss)(100) —
 (100)
Distributions to member
  (533)    (533)(1,940) —
 (1,940)
Contributions from member739
 —
 739
December 31, 2014$3,907
 —
 $3,907
     
Net income (loss)$(341) —
 $(341)
Other comprehensive income (loss)
   (2)      (2)(3) —
 (3)
December 31, 2011 - Successor (a)
 $ 3,741     $ 3,741 
      
      
Net income
 $ 219    $ 219 
Distributions to member
  (155)    (155)
Other comprehensive income (loss)
   (19)      (19)
December 31, 2012 - Successor (a)
 $ 3,786     $ 3,786 
Distributions to member (a)(412) —
 (412)
Contributions from member (a)1,152
 —
 1,152
December 31, 2015$4,303
 —
 $4,303

(a) Includes the contribution of RJS Power as of the acquisition date. See "General - Comprehensive Income" in NoteNotes 1 and 6 for disclosure of balances of each component of AOCI.additional information.

The accompanying Notes to the Consolidated Financial Statements are an integral part of the financial statements.


77

STATEMENTS OF INCOME
Louisville Gas and Electric Company
(Millions of Dollars)       
                 
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  December 31,
     2012  2011  2010   2010 
Operating Revenues             
 
Retail and wholesale
 $ 1,247  $ 1,281  $ 233   $ 978 
 
Electric revenue from affiliate
   77    83    21     79 
 
Total Operating Revenues
   1,324    1,364    254     1,057 
                 
Operating Expenses             
 Operation             
  
Fuel
   374    350    60     306 
  
Energy purchases
   163    209    61     142 
  
Energy purchases from affiliate
   12    36    2     13 
  
Other operation and maintenance
   363    363    67     281 
 
Depreciation
   152    147    23     115 
 
Taxes, other than income
   23    18    1     12 
 
Total Operating Expenses
   1,087    1,123    214     869 
                 
Operating Income
   237    241    40     188 
                 
Other Income (Expense) - net
   (3)   (2)   (3)    17 
                 
Interest Expense
   42    44    7     16 
                 
Interest Expense with Affiliate
         1     22 
                 
Income Before Income Taxes
   192    195    29     167 
                 
Income Taxes
   69    71    10     58 
                 
Net Income
 $ 123  $ 124  $ 19   $ 109 
Combined Notes to the Financial Statements

The accompanying Notes to Financial Statements are an integral part of the financial statements.
233
STATEMENTS OF COMPREHENSIVE INCOME
Louisville Gas and Electric Company
(Millions of Dollars)
                 
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010
                 
Net income
 $ 123  $ 124  $ 19   $ 109 
                 
Other comprehensive income (loss):             
Amounts arising during the period - gains (losses), net of tax             
 (expense) benefit:             
  Qualifying derivatives, net of tax of $0, $0, $0, ($7)             10 
Total other comprehensive income (loss)
             10 
                 
Comprehensive income
 $ 123  $ 124  $ 19   $ 119 
                 
The accompanying Notes to the Financial Statements are an integral part of the financial statements.

234
STATEMENTS OF CASH FLOWS
   
Louisville Gas and Electric Company   
(Millions of Dollars)   
      Successor  Predecessor
          Two Months  Ten Months
      Year Ended Year Ended Ended  Ended
      December 31, December 31, December 31,  October 31,
      2012  2011  2010   2010 
Cash Flows from Operating Activities             
 
Net income
 $ 123  $ 124  $ 19   $ 109 
 Adjustments to reconcile net income to net cash provided             
  by (used in) operating activities             
   
Depreciation
   152    147    23     115 
   
Amortization
   11    12    2     
   
Defined benefit plans - expense
   18    21    4     20 
   
Deferred income taxes and investment tax credits
   69    51    13     21 
   
Unrealized (gains) losses on derivatives
             14 
   Regulatory asset for previously recorded losses on             
    
interest rate swaps
             (22)
   
Other
   (13)   1    2     2 
 Change in current assets and current liabilities             
  
Accounts receivable
   (2)   25    (27)    (2)
  
Accounts payable
      (24)   17     
  
Accounts payable to affiliates
   (3)   6    (31)    23 
  
Unbilled revenues
   (7)   16    (38)    22 
  
Fuel, materials and supplies
      20    10     (22)
  
Taxes
   (7)   3        
  
Other
   (7)   (7)   (2)    (47)
 Other operating activities             
  
Defined benefit plans - funding
   (27)   (70)   (1)    (25)
  
Other assets
   (21)   (7)       (5)
  
Other liabilities
   22    7    1     (14)
   
Net cash provided by (used in) operating activities
   308    325    (8)    189 
Cash Flows from Investing Activities             
 
Expenditures for property, plant and equipment
   (286)   (196)   (65)    (155)
 
Proceeds from the sale of assets to affiliate
             48 
 
Proceeds from the sale of other investments
      163        
 Net (increase) decrease in restricted cash and cash             
  
equivalents
   (3)   (9)   2     
   
Net cash provided by (used in) investing activities
   (289)   (42)   (63)    (107)
Cash Flows from Financing Activities             
 
Net increase (decrease) in notes payable with affiliates
      (12)   (130)    (28)
 
Issuance of long-term debt with affiliate
         485     
 
Retirement of long-term debt with affiliate
         (485)    
 
Issuance of long-term debt
         531     
 
Net increase (decrease) in short-term debt
   55    (163)   163     
 
Repayment to E.ON AG affiliates
         (485)    
 
Debt issuance and credit facility costs
   (2)   (2)   (10)    
 
Payment of common stock dividends to parent
   (75)   (83)       (55)
   
Net cash provided by (used in) financing activities
   (22)   (260)   69     (83)
Net Increase (Decrease) in Cash and Cash Equivalents
   (3)   23    (2)    (1)
Cash and Cash Equivalents at Beginning of Period
   25    2    4     5 
Cash and Cash Equivalents at End of Period
 $ 22  $ 25  $ 2   $ 4 
                  
Supplemental Disclosures of Cash Flow Information             
 Cash paid (received) during the period for:             
  
Interest - net of amount capitalized
 $ 39  $ 40  $ 11   $ 39 
  
Income taxes - net
 $ 5  $ 20  $ (8)  $ 60 
                  
The accompanying Notes to Financial Statements are an integral part of the financial statements.
235
BALANCE SHEETS AT DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars, shares in thousands)
          
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
 $ 22  $ 25 
 Accounts receivable (less reserve: 2012, $1; 2011, $2)      
  
Customer
   59    60 
  
Other
   8    9 
 
Unbilled revenues
   72    65 
 
Accounts receivable from affiliates
   14    11 
 
Fuel, materials and supplies
   142    142 
 
Prepayments
   7    7 
 
Price risk management from affiliates
   7    
 
Income taxes receivable
   8    4 
 
Deferred income taxes
      2 
 
Regulatory assets
   19    9 
 
Other current assets
   1    
 
Total Current Assets
   359    334 
          
Property, Plant and Equipment      
 
Regulated utility plant
   3,187    2,956 
 
Less: accumulated depreciation - regulated utility plant
   220    116 
  
Regulated utility plant, net
   2,967    2,840 
 
Construction work in progress
   259    215 
 
Property, Plant and Equipment, net
   3,226    3,055 
          
Other Noncurrent Assets      
 
Regulatory assets
   400    403 
 
Goodwill
   389    389 
 
Other intangibles
   144    166 
 
Other noncurrent assets
   44    40 
 
Total Other Noncurrent Assets
   977    998 
          
Total Assets
 $ 4,562  $ 4,387 
          
The accompanying Notes to Financial Statements are an integral part of the financial statements.
236
BALANCE SHEETS AT DECEMBER 31,
Louisville Gas and Electric Company
(Millions of Dollars, shares in thousands)
     2012  2011 
Liabilities and Equity      
          
Current Liabilities      
 
Short-term debt
 $ 55    
 
Accounts payable
   117  $ 94 
 
Accounts payable to affiliates
   23    26 
 
Customer deposits
   23    22 
 
Taxes
   2    13 
 
Regulatory liabilities
   4    10 
 
Interest
   5    6 
 
Salaries and benefits
   18    14 
 
Deferred income taxes
   4    
 
Other current liabilities
   17    14 
 
Total Current Liabilities
   268    199 
          
Long-term Debt
   1,112    1,112 
       
Deferred Credits and Other Noncurrent Liabilities      
 
Deferred income taxes
   544    475 
 
Investment tax credits
   40    43 
 
Accrued pension obligations
   102    95 
 
Asset retirement obligations
   56    55 
 
Regulatory liabilities
   471    478 
 
Price risk management liabilities
   53    55 
 
Other deferred credits and noncurrent liabilities
   106    113 
 
Total Deferred Credits and Other Noncurrent Liabilities
   1,372    1,314 
          
Commitments and Contingent Liabilities (Notes 6 and 15)      
          
Stockholder's Equity      
 
Common stock - no par value (a)
   424    424 
 
Additional paid-in capital
   1,278    1,278 
 
Earnings reinvested
   108    60 
Total Equity
   1,810    1,762 
          
Total Liabilities and Equity
 $ 4,562  $ 4,387 

(a)75,000 shares authorized; 21,294 shares issued and outstanding at December 31, 2012 and December 31, 2011.

The accompanying Notes to Financial Statements are an integral part of the financial statements.
237
STATEMENTS OF EQUITY
Louisville Gas and Electric Company               
(Millions of Dollars)               
              
   Common           Accumulated   
  ��stock           other   
   shares     Additional     comprehensive   
   outstanding  Common  paid-in  Earnings  income   
   (a)  stock  capital  reinvested  (loss)  Total
                   
December 31, 2009 - Predecessor (b)
  21,294  $424  $84  $755  $ (10) $1,253 
Net income
           109       109 
Cash dividends declared on common stock
           (55)      (55)
Other comprehensive income (loss)
              10    10 
October 31, 2010 - Predecessor
 21,294  $ 424  $ 84  $ 809  $  $ 1,317 
                   
                   
Effect of PPL acquisition
      $ 1,194  $ (809)    $ 385 
Net income
           19       19 
December 31, 2010 - Successor
 21,294  $ 424  $ 1,278  $ 19     $ 1,721 
                   
                   
Net income
         $ 124     $ 124 
Cash dividends declared on common stock
           (83)      (83)
December 31, 2011 - Successor
  21,294  $ 424  $ 1,278  $ 60     $ 1,762 
                   
                   
Net income
         $ 123     $ 123 
Cash dividends declared on common stock
           (75)      (75)
December 31, 2012 - Successor
  21,294  $ 424  $ 1,278  $ 108     $ 1,810 

(a)      Shares in thousands.  All common shares of LG&E stock are owned by LKE.
(b)      See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
238
STATEMENTS OF INCOME
Kentucky Utilities Company
(Millions of Dollars)       
                 
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Operating Revenues             
 
Retail and wholesale
 $ 1,512  $ 1,512  $ 261   $ 1,235 
 
Electric revenue from affiliate
   12    36    2     13 
 
Total Operating Revenues
   1,524    1,548    263     1,248 
                 
Operating Expenses             
 Operation             
  
Fuel
   498    516    78     417 
  
Energy purchases
   32    29    7     68 
  
Energy purchases from affiliate
   77    83    21     79 
  
Other operation and maintenance
   384    362    65     271 
 
Depreciation
   193    186    26     119 
 
Taxes, other than income
   23    19    1     9 
 
Total Operating Expenses
   1,207    1,195    198     963 
                 
Operating Income
   317    353    65     285 
                 
Other Income (Expense) - net
   (8)   (1)       1 
                 
Other-Than-Temporary Impairments
   25           
                 
Interest Expense
   69    70    8     6 
                 
Interest Expense with Affiliate
         2     62 
                 
Income Before Income Taxes
   215    282    55     218 
                 
Income Taxes
   78    104    20     78 
                 
Net Income
 $ 137  $ 178  $ 35   $ 140 

The accompanying Notes to Financial Statements are an integral part of the financial statements.
239
STATEMENTS OF COMPREHENSIVE INCOME
Kentucky Utilities Company
(Millions of Dollars)
                 
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
                 
Net income
 $ 137  $ 178  $ 35   $ 140 
                 
Other comprehensive income (loss):             
Amounts arising during the period - gains (losses), net of tax             
 (expense) benefit:             
  Equity investees' other comprehensive income (loss), net of             
   
tax of ($1), $0, $0, $1
   1           (2)
Total other comprehensive income (loss)
   1           (2)
                 
Comprehensive income
 $ 138  $ 178  $ 35   $ 138 
                 
The accompanying Notes to Financial Statements are an integral part of the financial statements.
240
STATEMENTS OF CASH FLOWS
   
Kentucky Utilities Company   
(Millions of Dollars)   
      Successor  Predecessor
          Two Months  Ten Months
      Year Ended Year Ended Ended  Ended
      December 31, December 31, December 31,  October 31,
      2012  2011  2010   2010 
Cash Flows from Operating Activities             
 
Net income
 $ 137  $ 178  $ 35   $ 140 
 Adjustments to reconcile net income to net cash provided             
  by (used in) operating activities             
   
Depreciation
   193    186    26     119 
   
Amortization
   14    13    2     
   
Defined benefit plans - expense
   11    14    3     13 
   
Deferred income taxes and investment tax credits
   99    108    4     23 
   
Impairment of assets
   25           
   
Other
   10    (10)   12     (3)
 Change in current assets and current liabilities             
  
Accounts receivable
   (17)   22    (12)    13 
  
Accounts payable
   1    2    9     (17)
  
Accounts payable to affiliates
      (12)   (41)    46 
  
Unbilled revenues
   (3)   8    (32)    19 
  
Fuel, materials and supplies
   7    (5)   5     (6)
  
Taxes
   15    (14)   14     
  
Other
   6    (3)   6     10 
 Other operating activities             
  
Defined benefit plans - funding
   (21)   (50)   (2)    (18)
  
Other assets
   (3)   (2)       15 
  
Other liabilities
   26    9    1     (10)
   
Net cash provided by (used in) operating activities
   500    444    30     344 
Cash Flows from Investing Activities             
 
Expenditures for property, plant and equipment
   (480)   (279)   (89)    (292)
 
Purchases of assets from affiliate
             (48)
   
Net cash provided by (used in) investing activities
   (480)   (279)   (89)    (340)
Cash Flows from Financing Activities             
 
Issuance of short-term debt with affiliate
         33     
 
Retirement of short-term debt with affiliate
         (33)    
 
Net increase (decrease) in notes payable with affiliates
      (10)   (83)    48 
 
Issuance of long-term debt with affiliate
         1,298     
 
Retirement of long-term debt with affiliate
         (1,298)    
 
Issuance of long-term debt
         1,489     
 
Net increase (decrease) in short-term debt
   70           
 
Repayment to E.ON AG affiliates
         (1,331)    
 
Debt issuance and credit facility costs
      (3)   (17)    
 
Payment of common stock dividends to parent
   (100)   (124)       (50)
   
Net cash provided by (used in) financing activities
   (30)   (137)   58     (2)
Net Increase (Decrease) in Cash and Cash Equivalents
   (10)   28    (1)    2 
Cash and Cash Equivalents at Beginning of Period
   31    3    4     2 
Cash and Cash Equivalents at End of Period
 $ 21  $ 31  $ 3   $ 4 
                  
Supplemental Disclosures of Cash Flow Information             
 Cash paid (received) during the period for:             
  
Interest - net of amount capitalized
 $ 62  $ 60  $ 22   $ 62 
  
Income taxes - net
 $ (39) $ 16  $ (12)  $ 74 
                  
The accompanying Notes to Financial Statements are an integral part of the financial statements.
241
BALANCE SHEETS AT DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars, shares in thousands)
          
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
 $ 21  $ 31 
 Accounts receivable (less reserve: 2012, $2; 2011, $2)      
  
Customer
   74    69 
  
Other
   11    9 
 
Unbilled revenues
   84    81 
 
Accounts receivable from affiliates
   7    
 
Fuel, materials and supplies
   134    141 
 
Prepayments
   10    7 
 
Price risk management assets from affiliates
   7    
 
Income taxes receivable
   2    5 
 
Deferred income taxes
   3    5 
 
Other current assets
   3    3 
 
Total Current Assets
   356    351 
          
Investments
      31 
          
Property, Plant and Equipment      
 
Regulated utility plant
   4,886    4,563 
 
Less: accumulated depreciation - regulated utility plant
   299    161 
  
Regulated utility plant, net
   4,587    4,402 
 
Other, net
   1    
 
Construction work in progress
   490    340 
 
Property, Plant and Equipment, net
   5,078    4,742 
          
Other Noncurrent Assets      
 
Regulatory assets
   230    217 
 
Goodwill
   607    607 
 
Other intangibles
   127    148 
 
Other noncurrent assets
   57    60 
 
Total Other Noncurrent Assets
   1,021    1,032 
          
Total Assets
 $ 6,455  $ 6,156 
          
The accompanying Notes to Financial Statements are an integral part of the financial statements.
242
BALANCE SHEETS AT DECEMBER 31,
Kentucky Utilities Company
(Millions of Dollars, shares in thousands)
     2012  2011 
Liabilities and Equity      
          
Current Liabilities      
 
Short-term debt
 $ 70    
 
Accounts payable
   147  $ 112 
 
Accounts payable to affiliates
   33    33 
 
Customer deposits
   25    23 
 
Taxes
   26    11 
 
Regulatory liabilities
   5    10 
 
Interest
   10    11 
 
Salaries and benefits
   17    15 
 
Other current liabilities
   16    13 
 
Total Current Liabilities
   349    228 
          
Long-term Debt
   1,842    1,842 
       
Deferred Credits and Other Noncurrent Liabilities      
 
Deferred income taxes
   587    484 
 
Investment tax credits
   98    101 
 
Accrued pension obligations
   104    83 
 
Asset retirement obligations
   69    61 
 
Regulatory liabilities
   531    525 
 
Other deferred credits and noncurrent liabilities
   92    87 
 
Total Deferred Credits and Other Noncurrent Liabilities
   1,481    1,341 
          
Commitments and Contingent Liabilities (Notes 6 and 15)      
          
Stockholder's Equity      
 
Common stock - no par value (a)
   308    308 
 
Additional paid-in capital
   2,348    2,348 
 
Accumulated other comprehensive income (loss)
   1    
 
Earnings reinvested
   126    89 
 
Total Equity
   2,783    2,745 
          
Total Liabilities and Equity
 $ 6,455  $ 6,156 

(a)      80,000 shares authorized; 37,818 shares issued and outstanding at December 31, 2012 and December 31, 2011.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
243
STATEMENTS OF EQUITY
Kentucky Utilities Company            
(Millions of Dollars)            
             
  Common           Accumulated   
  stock           other   
  shares     Additional     comprehensive   
  outstanding  Common  paid-in  Earnings  income   
  (a)  stock  capital  reinvested  (loss)  Total
                  
December 31, 2009 - Predecessor
  37,818  $308  $316  $1,328     $ 1,952 
Net income
           140       140 
Cash dividends declared on common stock
           (50)      (50)
Other comprehensive income (loss)
            $ (2)   (2)
October 31, 2010 - Predecessor (b) 37,818  $ 308  $ 316  $ 1,418  $ (2) $ 2,040 
                  
                  
Effect of PPL acquisition
      $ 2,032  $ (1,418) $ 2  $ 616 
Net income
           35       35 
December 31, 2010 - Successor 37,818  $ 308  $ 2,348  $ 35  $  $ 2,691 
                  
                  
Net income
         $ 178     $ 178 
Cash dividends declared on common stock
           (124)      (124)
December 31, 2011 - Successor
 37,818  $ 308  $ 2,348  $ 89     $ 2,745 
                  
                  
Net income
         $ 137     $ 137 
Cash dividends declared on common stock
           (100)      (100)
Other comprehensive income (loss)
            $ 1    1 
December 31, 2012 - Successor (b)
 37,818  $ 308  $ 2,348  $ 126  $ 1  $ 2,783 

(a)      Shares in thousands.  All common shares of KU stock are owned by LKE.
(b)      See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI.
The accompanying Notes to Financial Statements are an integral part of the financial statements.
244

COMBINED NOTES TO FINANCIAL STATEMENTS

1.  Summary of Significant Accounting Policies

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

General

Capitalized terms and abbreviations appearing in the combined notes to the financial statements are explaineddefined in the glossary. Dollars are in millions, except per share data, unless otherwise noted. As Talen Energy Corporation is substantially comprised of Talen Energy Supply, LLC and its subsidiaries, to avoid repetition, most disclosures refer to Talen Energy which indicates the disclosure applies to Talen Energy Corporation and Talen Energy Supply, LLC. This presentation has been applied where identification of particular subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a particular registrant or subsidiary is considered important to understanding the matter being disclosed, the specific entity's name is used, in particular, for those few disclosures that apply only to Talen Energy Corporation. Each disclosure referring to a subsidiary applies to both Talen Energy Corporation and Talen Energy Supply and each disclosure referring to Talen Energy Supply applies to Talen Energy Corporation through consolidation.

Business and ConsolidationBasis of Presentation

(PPL)Business - Spinoff from PPL and formation of Talen Energy Corporation

PPLTalen Energy Corporation, through its principal subsidiary Talen Energy Supply, is ana competitive energy and utility holdingpower generation company that, through its subsidiaries, is primarily engaged in:  1)in the regulated generation, transmission, distributionproduction and sale of electricity, capacity and the regulated distribution and sale of natural gas, primarily in Kentucky; 2) the regulated distribution of electricity in the U.K.; 3) the regulated transmission, distribution and sale of electricity in Pennsylvania; and 4) the competitive generation and marketing of electricity in portions of the northeastern and northwestern U.S.  Headquarteredrelated products. Talen Energy is headquartered in Allentown, PA, PPL's principal subsidiaries are LKE (including its principal subsidiaries, LG&EPennsylvania and KU), PPL Global, PPL Electric and PPL Energy Supply (including its principal subsidiaries, PPL EnergyPlus and PPL Generation).  PPL's corporate level financing subsidiary is PPL Capital Funding.

On April 1, 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently referred to as WPD Midlands), from subsidiaries of E.ON AG.  WPD Midlands' operating results are included in PPL's results of operations for the full year of 2012, but as PPL is consolidating WPD Midlands on a one-month lag, eight months of operating results are included in PPL's results of operations for 2011 with no comparable amounts for 2010.

On November 1, 2010, PPL acquired all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG.  Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC.  LKE's operating results are included in PPL's results of operations for the full years of 2012 and 2011, while 2010 includes LKE's operating results for the two months ended December 31, 2010.

See Note 10 for additional information regarding the acquisitions of WPD Midlands and LKE.

(PPL and PPL Energy Supply)

In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the Ironwood Acquisition.  See Note 10 for additional information.

(PPL, LKE, LG&E and KU)

LKE is a holding company with cost-based rate-regulated utility operations through its subsidiaries, LG&E and KU, and is subject to PUHCA.  LG&E and KU are engaged in the regulated generation, transmission, distribution and sale of electricity.  LG&E also engages in the regulated distribution and sale of natural gas.  LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names.  KU also serves customers in Virginia (under the Old Dominion Power name) and in Tennessee.

(LKE, LG&E and KU)

LKE's, LG&E's and KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor.  Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting.  Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE, LG&E and KU have not changed as a result of the acquisition.
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(PPL and PPL Energy Supply)

PPL Generation owns and operates a portfolio of competitive domestic power generating assets.  These power plants aregeneration assets principally located in Pennsylvaniathe Northeast, Mid-Atlantic and Montana and use well-diversified fuel sources including coal, uranium, natural gas, oil and water.  PPL EnergyPlus sells electricity produced by PPL Generation subsidiaries, participates in wholesale market load-following auctions, and markets various energy products and commodities such as:  capacity, transmission, FTRs, coal, natural gas, oil, uranium, emission allowances, RECs and other commodities in competitive wholesale and competitive retail markets, primarily inSouthwest regions of the northeastern and northwestern U.S.

(In June 2014, PPL and Talen Energy Supply)Supply executed definitive agreements with the Riverstone Holders to combine their competitive power generation businesses into a new, stand-alone, publicly traded company named Talen Energy Corporation. On June 1, 2015, PPL completed the spinoff to PPL shareowners of a newly formed entity, Talen Energy Holdings, Inc. (Holdco), which at such time owned all of the membership interests of Talen Energy Supply and all of the common stock of Talen Energy Corporation. Immediately following the spinoff, Holdco merged with a special purpose subsidiary of Talen Energy Corporation, with Holdco continuing as the surviving company to the merger and as a wholly owned subsidiary of Talen Energy Corporation and the sole owner of Talen Energy Supply. PPL does not have an ownership interest in Talen Energy Corporation after completion of the spinoff. Substantially contemporaneous with the spinoff and merger, RJS Power was contributed by the Riverstone Holders to become a subsidiary of Talen Energy Supply (referred to as the "combination" or the "acquisition"). Subsequent to the acquisition, RJS Power was merged into Talen Energy Supply. Talen Energy has treated the combination with RJS Power as an acquisition, with Talen Energy Supply considered the accounting acquirer in accordance with business combination accounting guidance. See Note 3 for information on Talen Energy Corporation's common shares issued as a result of the formation of Talen Energy Corporation. See Note 6 for additional information on the acquisition.

Following the announcement of the transaction to form Talen Energy, efforts were initiated to identify the appropriate staffing for Talen Energy following completion of the spinoff. Organizational plans were substantially completed in 2014. The organizational plans identified the need to resize and restructure the Talen Energy organization and as a result, in 2014, charges of $16 million for employee separation benefits were recorded in "Operation and maintenance" on the Statement of Income and in "Other current liabilities" on the Balance Sheet, related to 112 eliminated positions. The separation benefits include cash severance compensation, lump sum COBRA reimbursement payments and outplacement services. At December 31, 2014, the recorded liability related to separation benefits was $9 million and included in "Other current liabilities" on the Balance Sheets. Most separations and payment of separation benefits have now been completed and the recorded liability at December 31, 2015 was insignificant.

In connection with the spinoff transaction, additional employee-related costs were incurred primarily related to accelerated stock-based compensation and pro-rated performance-based cash incentive and stock-based compensation awards previously issued under PPL stock incentive programs, primarily for Talen Energy Supply employees and for PPL employees who became Talen Energy Supply employees in connection with the transaction.  These costs were recognized at the closing of the spinoff. During 2015, Talen Energy Supply recorded $25 million related to these accelerated stock-based compensation and pro-rated stock-based compensation awards at spinoff. As the vesting for all Talen Energy Supply employees was accelerated and all remaining unrecognized compensation expense accelerated concurrently with the spinoff, Talen Energy does not expect to recognize future compensation costs for equity awards from PPL stock incentive programs held by Talen Energy Supply employees. See Note 8 for additional information on stock-based compensation.

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In January 2011,addition, during 2015, Talen Energy incurred $12 million of restructuring costs related to the spinoff transaction which are recorded in "Operation and maintenance" on the Statements of Income.

Prior to completion of the spinoff, Talen Energy Supply's financial statements included certain transactions with affiliates of PPL, which were disclosed as related party transactions. After June 1, 2015, all transactions with PPL or its affiliates are no longer related party transactions. See Note 12 for additional information on related party transactions.

Following the spinoff, certain services, including information technology, financial and accounting, human resource and other specified services are provided by PPL on a transition basis pursuant to the TSA. The TSA with PPL is for a period of up to two years from the date of the spinoff. For 2015, the costs incurred for these services were $23 million. See Note 12 for information on the TSA with Topaz Power Management, LP.

In connection with the FERC approval of the combination of Talen Energy Supply distributed its membership interest inwith RJS Power, PPL, Global, representing allTalen Energy and RJS Power agreed that within twelve months following the closing of the outstanding membership interesttransaction, Talen Energy would enter into an agreement to divest between 1,300 MW and 1,400 MW of PPL Global,assets in one of two groups of assets (both of which include the Sapphire facilities within PJM and the first of which also included the Holtwood, Lake Wallenpaupack and C.P. Crane facilities and the other of which includes the Ironwood facility) and to PPLlimit PJM energy market offers from assets it would retain in the other group to cost-based offers. In September 2015, Talen Energy requested that the FERC approve a third option for complying with the mitigation requirement that consists of divesting the Holtwood, Lake Wallenpaupack, C.P. Crane and Ironwood facilities, and will have the ability to retain the Sapphire facilities located in PJM, provided PJM energy market offers from such retained assets are limited to cost-based offers. In October 2015, Talen Energy entered into agreements to sell the Holtwood, Lake Wallenpaupack, Ironwood and C.P. Crane facilities. In November 2015, the FERC accepted the alternative plan on the terms requested. See Note 6 for information on the sales.

Basis of Presentation

Talen Energy Corporation's obligation to report under the Securities and Exchange Act of 1934, as amended, commenced on May 1, 2015, the date Talen Energy Corporation's Registration Statement on Form S-1 relating to the spinoff transaction was declared effective by the SEC. Talen Energy Supply is a separate registrant and is considered the accounting predecessor of Talen Energy Corporation. Therefore, the financial information prior to June 1, 2015 presented in this Annual Report on Form 10-K for both registrants includes only legacy Talen Energy Supply information. From June 1, 2015, upon completion of the spinoff and acquisition, Talen Energy Corporation's and Talen Energy Supply's parent, PPLconsolidated financial information also includes RJS. As such, Talen Energy Funding.  The distribution was made basedCorporation's and Talen Energy Supply's consolidated financial information presented in this Annual Report on Form 10-K for the book value2015 period represents twelve months of legacy Talen Energy Supply information consolidated with seven months of RJS information, while the2014 and earlier periods represent only legacy Talen Energy Supply information.

The assets and liabilities related to the Holtwood, Lake Wallenpaupack, C.P. Crane and Ironwood facilities have been classified as "Assets held for sale" and "Liabilities held for sale" at December 31, 2015 but their operating results have not been reclassified to "Income (Loss) from Discontinued Operations (net of PPL Globalincome taxes)" on the Statements of Income in accordance with financial effect as of January 1, 2011.the new accounting guidance on reporting discontinued operations. See Note 96 for additional information.

(PPL, PPL Energy Supplyinformation on these announced divestitures and LKE)"New Accounting Guidance Adopted - Reporting of Discontinued Operations" below for additional information on this new accounting guidance.

"Income (Loss) from Discontinued Operations (net of income taxes)" on the 2014 and 2013 Statements of Income includesrepresents the activitiesoperating results of various businesses that wereTalen Montana's hydroelectric generating facilities sold or distributed.  See Note 9 for additional information.in the fourth quarter of 2014.  The Statements of Cash Flows do not separately report the cash flows of discontinued operations. See Note 6 for additional information.

As described above, as part of the Discontinued Operations, exceptFERC approval of the combination with RJS Power as part of the spinoff transaction, certain assets were required to be disposed of under a mitigation plan. Under GAAP, assets acquired through a business combination that are immediately classified as held for sale should be classified as a discontinued operation from the date of acquisition. The Sapphire portfolio was included in both of the original divestiture packages approved by the FERC when approving the combination with RJS Power. Therefore, the Sapphire portfolio met the criteria for classification as assets and liabilities held for sale on the balance sheet and as discontinued operations on the statement of income upon acquisition. In November 2015, when the FERC approved the third mitigation package excluding the Sapphire portfolio as discussed above, the assets and liabilities and operating results were reclassified to held and used and to continuing operations as the sale of the Sapphire portfolio was no longer probable and therefore, no longer met the held for sale criteria. When this reclassification occurred, an

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impairment charge was recorded based on the then current estimated fair values of the facilities. See Notes 14 and 16 for additional information on the impairment charges for the LKE Predecessor period, which separately discloses these cash flows within operating, investing and financing activities, consistent with LKE's pre-acquisition accounting policy.

(PPL and PPL Electric)

PPL Electric is a cost-based rate-regulated subsidiary of PPL.  PPL Electric's principal business is the regulated transmission and distribution of electricity to serve retail customers in its franchised territory in eastern and central Pennsylvania and the regulated supply of electricity to retail customers in that territory as a PLR.

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)Sapphire plants.

The financial statements of the RegistrantsTalen Energy include each company's own accounts as well as the accounts of all entities in which the company has a controlling financial interest. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for VIEs. The Registrants consolidateTalen Energy consolidates a VIE when they are determined to have a controlling interest in the VIE, and thus are the primary beneficiary of the entity. For PPL and PPLTalen Energy Supply, see Note 22 for information regarding a consolidated VIE.is not the primary beneficiary in any material VIEs. Investments in entities in which a company has the ability to exercise significant influence but does not have a controlling financial interest are accounted for under the equity method. All other investments are carried at cost or fair value. All significant intercompany transactions have been eliminated. Any noncontrolling interests are reflected in the financial statements.

The financial statements of PPL, PPLTalen Energy Supply, LKE, LG&E and KU include their share of any undivided interests in jointly owned facilities, as well as their share of the related operating costs of those facilities. See Note 1410 for additional information.

(PPL)

PPL consolidates WPD, including WPD Midlands, on a one-month lag.  Material intervening events, such as debt issuances that occur in the lag period, are recognized in the current period financial statements.  Events that are significant but not material are disclosed.
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Regulation

(PPL, PPL Electric, LKE, LG&E and KU)

PPL Electric, LG&E and KU are cost-based rate-regulated utilities for which rates are set by regulators to enable PPL Electric, LG&E and KU to recover the costs of providing electric or gas service, as applicable, and to provide a reasonable return to shareholders.  Rates are generally established based on a historical test period adjusted to exclude unusual or nonrecurring items.  As a result, the financial statements are subject to the accounting for certain types of regulation as prescribed by GAAP and reflect the effects of regulatory actions.  Regulatory assets are recognized for the effect of transactions or events where future recovery of underlying costs is probable in regulated customer rates.  The effect of such accounting is to defer certain or qualifying costs that would otherwise currently be charged to expense.  Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates.  In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.  The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC or the applicable state regulatory commissions.  See Note 6 for additional details regarding regulatory matters.

(PPL)

WPD operates in an incentive-based regulatory structure under distribution licenses granted by Ofgem.  Electricity distribution revenues are set by Ofgem every five years through price control reviews that are not directly based on cost recovery.  The price control formula that governs WPD's allowed revenue is designed to provide economic incentives to minimize operating, capital and financing costs.  As a result, WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities.

Accounting Records(PPL, PPL Electric, LKE, LG&E and KU)

The system of accounts for domestic regulated entities is maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the applicable state regulatory commissions.

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Loss Accruals

Potential losses are accrued when (1) information is available that indicates it is "probable" that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The RegistrantsTalen Energy continuously assessassesses potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss accruals for environmental remediation are discounted when appropriate.

The accrual of contingencies that might result in gains is not recorded, unless realization is assured.Reclassifications

Changes in Classification

The classification of certainCertain amounts in the 2011 and 2010prior period financial statements have been changedreclassified to conform to current period's presentation, including the current presentation.change in presentation discussed below. The changes in classificationreclassifications did not affect the Registrants'operating income, net income or equity.
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Comprehensive Income(PPL, PPL Energy Supply, LKE, LG&E and KU)

Comprehensive income, which includes net incomeIn these financial statements, revenue and OCI,expense from derivatives is shownrecorded based on Talen Energy's economic hedging strategy. For example, all purchases and sales associated with economic hedging of the sale of energy using contracts accounted for as derivatives are recorded within "Operating Revenues" and all purchases and sales associated with economic hedging of the procurement of fuel or purchasing energy using contracts accounted for as derivatives are recorded as "Operating Expenses" on the Statements of Comprehensive Income. Prior to 2015, Talen Energy classified all non-trading commodity hedge transactions as revenue or expense based upon whether each specific transaction was a sale or purchase, which in certain instances, created losses within revenue and gains within expense. As a result of this change in presentation, there was an equal and offsetting increase of $845 million in 2014 and a decrease of $19 million in 2013 primarily in "Wholesale energy" and "Energy purchases" on the Statements of Income.

AOCI, which is presented on the Balance Sheets of PPL and included in Member's equity on the Balance Sheets of PPL Energy Supply and LKE, consisted of the following after-tax gains (losses).

     Unrealized gains (losses)    Defined benefit plans   
  Foreign                  
  currency Available-    Equity Prior Actuarial Transition   
  translation for-sale Qualifying investees' service gain asset   
  adjustments securities derivatives AOCI costs (loss) (obligation) Total
PPL                       
                         
December 31, 2009$ (136) $ 62  $ 602  $ (2) $ (61) $ (993) $ (9) $ (537)
OCI  (59)   24    93       29    (39)   10    58 
December 31, 2010$ (195) $ 86  $ 695  $ (2) $ (32) $ (1,032) $ 1  $ (479)
                         
OCI  (48)   2    (168)   3    7    (105)      (309)
December 31, 2011$ (243) $ 88  $ 527  $ 1  $ (25) $ (1,137) $ 1  $ (788)
                         
OCI  94    22    (395)   2    11    (886)      (1,152)
December 31, 2012$ (149) $ 110  $ 132  $ 3  $ (14) $ (2,023) $ 1  $ (1,940)
                         
PPL Energy Supply                       
                         
December 31, 2009$ (136) $ 62  $ 573  $ (2) $ (44) $ (930) $ (7) $ (484)
OCI  (59)   24    159       21    (23)   7    129 
December 31, 2010$ (195) $ 86  $ 732  $ (2) $ (23) $ (953) $  $ (355)
                         
OCI     2    (86)   3    2    (18)      (97)
Distribution of membership                       
 interest in PPL Global (a)  195       (41)      5    780       939 
December 31, 2011$  $ 88  $ 605  $ 1  $ (16) $ (191)    $ 487 
                         
OCI     22    (395)      6    (72)      (439)
December 31, 2012   $ 110  $ 210  $ 1  $ (10) $ (263)    $ 48 

(a)
See Note 9 for additional information.                  

          Defined benefit plans   
  Foreign Unrealized          
  currency gains (losses) Equity Prior      
  translation on qualifying investees' service Actuarial   
  adjustments derivatives AOCI costs gain (loss) Total
LKE                 
                   
December 31, 2009 - Predecessor$ 11  $ (6)    $ (12) $ (36) $ (43)
Disposal of discontinued operations  (11)               (11)
OCI     10  $ (2)   1    (19)   (10)
October 31, 2010 - Predecessor$  $ 4  $ (2) $ (11) $ (55) $ (64)
                   
Effect of PPL acquisition     (4)   2    11    55    64 
OCI              6    6 
December 31, 2010 - Successor   $  $  $  $ 6  $ 6 
                   
OCI           (2)      (2)
December 31, 2011 - Successor         $ (2) $ 6  $ 4 
                   
OCI        1       (20)   (19)
December 31, 2012 - Successor      $ 1  $ (2) $ (14) $ (15)

LG&E had an AOCI balance that was a loss of $10 million at December 31, 2009 (a Predecessor period).  LG&E had no AOCI balances at December 31, 2010, 2011 or 2012 (Successor periods).  During the ten months ended October 31, 2010 (a Predecessor period), LG&E had $10 million of gains on qualifying derivatives that were recorded in OCI.

KU had no AOCI balances at December 31, 2009 (a Predecessor period), 2010 or 2011 (Successor periods). KU had an AOCI balance that was a gain of $1 million at December 31, 2012 (a Successor period) related to an equity investee's AOCI.  KU recorded $2 million of losses related to an equity investee's OCI during the ten months ended October 31, 2010 (a Predecessor period), which were eliminated with the effect of the PPL acquisition.
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Earnings Per Share for Talen Energy Corporation

See Note 3 for information on the calculation of EPS.

(PPL)Price Risk Management

EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareowners.  Share-based payment awards that provide recipients a non-forfeitable right to dividends or dividend equivalents are considered participating securities.

Price Risk Management

(PPL, PPL Energy Supply, LKE, LG&E and KU)

Energy and energy-related contracts are used to hedge the variability of expected cash flows associated with the competitive generating units and marketing activities, as well as for trading purposes. Interest rate contracts are usedmay be utilized to hedge exposures to changes in the fair value of debt instruments and to hedge exposures to variability in expected cash flows associated with existing floating-rate debt instruments or forecasted fixed-rate issuances of debt. Foreign currency exchange contracts are used to hedge foreign currency exchange exposures, primarily associated with PPL's investments in U.K. subsidiaries.  Similar derivatives may receive different accounting treatment, depending on management's intended use and documentation.


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Certain energy and energy-related contracts meet the definition of a derivative, while others do not meet the definition of a derivative because they lack a notional amount or a net settlement provision. In cases where there is no net settlement provision, markets are periodically assessed to determine whether market mechanisms have evolved that would facilitate net settlement. Certain derivative energy contracts have been excluded from the requirements of derivative accounting treatment because they meet the definition of NPNS.NPNS has been elected. These contracts are accounted for using accrual accounting. All other contracts that have been classified as derivative contracts are reflected on the balance sheetsheets at their fair value. These contracts are recorded as "Price risk management assets" and "Price risk management liabilities" on the Balance Sheets. The portion of derivative positions that deliversettle within a year are included in "Current Assets" and "Current Liabilities," while the portion of derivative positions that deliversettle beyond a year are recorded in "Other Noncurrent Assets" and "Deferred Credits and Other Noncurrent Liabilities." Talen Energy considers intra-month transactions to be spot activity, which is not accounted for as a derivative.

Energy and energy-related contracts are assigned a strategy and accounting classification. Processes exist that allow for subsequent review and validation of the contract information. These strategies are discussed inSee Note 15 for more detail in Note 19.information. The accounting department provides the traders and the risk management department with guidelines on appropriate accounting classifications for various contract types and strategies. Some examples of these guidelines include, but are not limited to:
·  Physical coal, limestone, lime, uranium, electric transmission, gas transportation, gas storage and renewable energy credit contracts are not derivatives due to the lack of net settlement provisions.
·  Only contracts where physical delivery is deemed probable throughout the entire term of the contract can qualify for NPNS.
·  Physical transactions that permit cash settlement and financial transactions do not qualify for NPNS because physical delivery cannot be asserted; however, these transactions can receive cash flow hedge treatment if they lock in the future cash flows for energy-related commodities.
·  Certain purchased option contracts or net purchased option collars may receive hedge accounting treatment.  Those that are not eligible are recorded at fair value through earnings.
·  Derivative transactions that do not qualify for NPNS or hedge accounting treatment are recorded at fair value through earnings.

Physical coal, limestone, lime, uranium, electric transmission, gas transportation, gas storage and renewable energy credit contracts not traded on an exchange are not derivatives due to the lack of net settlement provisions.

Only contracts where physical delivery is deemed probable throughout the entire term of the contract can qualify for NPNS.

Derivative transactions that do not qualify for NPNS, or for which NPNS treatment is not elected, are recorded at fair value through earnings.

A similar process is also followed by the treasury department as it relates to interest rate and foreign currency derivatives. Examples of accounting guidelines provided to the treasury department staff include, but are not limited to:
·  Transactions to lock in an interest rate prior to a debt issuance can be designated as cash flow hedges, to the extent the forecasted debt issuances remain probable of occurring.
·  Cross-currency transactions to hedge interest and principal repayments can be designated as cash flow hedges.
·  Transactions entered into to hedge fluctuations in the fair value of existing debt can be designated as fair value hedges.
·  Transactions entered into to hedge the value of a net investment of foreign operations can be designated as net investment hedges.

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·  Derivative transactions that do not qualify for hedge accounting treatment are marked to fair value through earnings.  These transactions generally include foreign currency swaps and options to hedge GBP earnings translation risk associated with PPL's U.K. subsidiaries that report their financial statements in GBP.  As such, these transactions reduce earnings volatility due solely to changes in foreign currency exchange rates.
·  Derivative transactions may be marked to fair value through regulatory assets/liabilities if approved by the appropriate regulatory body.  These transactions generally include the effect of interest rate swaps that are included in customer rates.

Transactions to lock in an interest rate prior to a debt issuance can be designated as cash flow hedges, to the extent the forecasted debt issuances remain probable of occurring.

Transactions entered into to hedge fluctuations in the fair value of existing debt can be designated as fair value hedges.

Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing activities on the Statements of Cash Flows, depending on the underlying natureclassification of the hedged items.

PPL and its subsidiaries haveTalen Energy has elected not to offset net derivative positions against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.

PPLTalen Energy Supply reflects its net realized and unrealized gains and losses associated with all derivatives that are held for trading purposes in "Net energy trading margins""Wholesale energy" on the Statements of Income.

See Notes 1814 and 1915 for additional information on derivatives.

(PPL and PPL Electric)

To meet its obligation as a PLR to its customers, PPL Electric has entered into certain contracts that meet the definition of a derivative.  However, these contracts qualify for NPNS.  See Notes 18 and 19 for additional information.

Revenue

Utility Revenue(PPL)

For the years ended December 31, the Statements of Income "Utility" line item contains rate-regulated revenue from the following:    

    2012   2011   2010 
          
Domestic electric and gas revenue (a) $ 4,519  $ 4,674  $ 2,941 
U.K. electric revenue (b)   2,289    1,618    727 
 Total $ 6,808  $ 6,292  $ 3,668 

(a)Represents revenue from regulated generation, transmission and/or distribution in Pennsylvania, Kentucky, Virginia and Tennessee, including regulated wholesale revenue.  2010 includes two months of revenue for LKE.
(b)Represents electric distribution revenue from the operation of WPD's distribution networks.  2011 includes eight months of revenue for WPD Midlands.

Revenue Recognition

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&EOperating revenues from the sale of energy, capacity and KU)ancillary services are recognized when the product or service is delivered to a customer or contractually earned, unless they meet the definition of and are accounted for as derivatives. See "Accounting and Reporting" in Note 15 for additional information on the accounting for derivatives.

Operating revenues except for certain energy and energy-related contracts that meet the definition of derivative instruments and "Energy-related businesses," are recorded based on energy deliveries through the end of the calendar month. Unbilled retail revenues result because customers' meters are read and bills are rendered throughout the month, rather than all being read at the end of the month. Unbilled revenues for a month are calculated by multiplying an estimate of unbilled kWh by the estimated average cents per kWh. Unbilled wholesale energy revenues are recorded at month-end to reflect estimated amounts until actual dollars and MWhs are confirmed and invoiced. Any differenceImmaterial differences between estimated and actual revenues isare adjusted the following month.
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Certain PPL subsidiaries participate primarily in the PJM RTO, as well as in other RTOs and ISOs.  In PJM, PPL EnergyPlus is a marketer, a load-serving entity and a seller for PPL Energy Supply's generation subsidiaries.  A function of interchange accounting is to match participants' MWh entitlements (generation plus scheduled bilateral purchases) against their MWh obligations (load plus scheduled bilateral sales) during every hour of every day.  If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the RTO at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase at the respective market price for that hour.  PPL Energy Supply records the hourly net sales in its Statements of Income as "Wholesale energy marketing" if in a net sales position and "Energy purchases" if in a net purchase position.

(PPL)

WPD's revenue is primarily from charges to suppliers to use its distribution system to deliver electricity to the end-user.  WPD's allowed revenue is not dependent on volume delivered over the five-year price control period.  However, in any fiscal period, WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the allowed revenue for a given period.  Under recoveries are recovered and recorded in the next regulatory year.  Over recoveries are reflected in the current period as a liability and are not included in revenue.

(PPL and PPL Energy Supply)

PPL Energy Supply records non-derivative energy marketing activity in the period when the energy is delivered.  Generally, sales contracts held for non-trading purposes are reported gross on the Statements of Income within "Wholesale energy marketing" and "Unregulated retail electric and gas."  However, non-trading physical sales and purchases of electricity at major market delivery points (which is any delivery point with liquid pricing available, such as the pricing hub for PJM West), are netted and reported in the Statements of Income within "Wholesale energy marketing" or "Energy purchases," depending on the net hourly position.  Certain energy and energy-related contracts that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense (see Note 19), unless hedge accounting is applied.  If derivatives meet cash flow hedging criteria, changes in fair value are recorded in AOCI.  Derivative and non-derivative contracts that are designated as proprietary trading activities are reported net on the Statements of Income within "Net energy trading margins."

"Energy-related businesses" revenue primarily includes revenue from theTalen Energy's mechanical contracting and engineering subsidiaries. The mechanical contracting and engineeringThese subsidiaries record revenue from construction contracts on the percentage-of-completion method of accounting, measured by the actual cost incurred to date as a percentage of the estimated total cost for each contract.

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Accordingly, costs and estimated earnings in excess of billings on uncompleted contracts are recorded within "Unbilled revenues" on the Balance Sheets, and billings in excess of costs and estimated earnings on uncompleted contracts are recorded within "Other current liabilities" on the Balance Sheets. The amount of costs and estimated earnings in excess of billings was $12$18 million and $15$20 million at December 31, 20122015 and 2011,2014, and the amount of billings in excess of costs and estimated earnings was $70$44 million and $59$41 million at December 31, 20122015 and 2011.2014.

During 2015, Talen Energy recorded a $7 million decrease to "Retail energy" revenues on the Statements of Income. Prior to the spinoff, Talen Energy billed and collected amounts from a third party that had a transmission operating agreement with Talen Energy's former affiliate, PPL Electric. Such amounts should have been recognized as an affiliate payable, but were inadvertently recorded as revenue. The $4 million after-tax impact ($0.04 per share for Talen Energy Corporation) of correcting this overstatement of "Retail energy" revenues decreased "Income (Loss) from Continuing Operations after Income Taxes" and "Net Income (Loss)" on the 2015 Statement on Income. The impact of the overstatement was not material to the previously-issued financial statements and the correction was not material to the full year results for 2015.

During 2014, Talen Energy recorded a $17 million increase to "Energy-related businesses" revenues and "Income (Loss) from Continuing Operations before Income Taxes" on the 2014 Statement of Income related to the timing of revenue recognition for a mechanical contracting and engineering subsidiary in prior periods. The $10 million after-tax impact ($0.13 per share for Talen Energy Corporation) of correcting this error increased "Income (Loss) from Continuing Operations after Income Taxes" and "Net Income (Loss)" in 2014. The impact of the error was not material to the previously-issued financial statements and the correction was not material to the full year results for 2014.

Accounts Receivable

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Accounts receivable are reported on the Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition.  See Note 10 for information related to the acquisitions of WPD Midlands and LKE.

(PPL, PPL Energy Supply and PPL Electric)

In accordance with a PUC-approved purchase of accounts receivable program, PPL Electric purchases certain accounts receivable from alternative suppliers (including PPL EnergyPlus) at a nominal discount, which reflects a provision for uncollectible accounts.  The alternative suppliers have no continuing involvement or interest in the purchased accounts receivable.  The purchased accounts receivable are initially recorded at fair value using a market approach based on the purchase price paid and are classified as Level 2 in the fair value hierarchy.  PPL Electric receives a nominal fee for administering its program.  During 2012, 2011 and 2010, PPL Electric purchased $848 million, $875 million and $617 million of accounts receivable from unaffiliated third parties.  During 2012, 2011 and 2010, PPL Electric purchased $313 million, $264 million and $215 million of accounts receivable from PPL EnergyPlus.
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Allowance for Doubtful Accounts(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Accounts receivable collectability is evaluated using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness and economic conditions. Specific events, such as bankruptcies, are also considered. Adjustments to the allowance for doubtful accounts are made when necessary based on the results of analysis, the aging of receivables and historical and industry trends.

Accounts receivable are written off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable previously written off are recorded when it is known they will be received.

The changes in the allowance for doubtful accounts were:

      Additions         
  Balance at   Charged to     Balance at
  Beginning of Period Charged to Income Other Accounts Deductions (a) End of Period
PPL                    
2012  $ 54   $ 55 (c)     $ 45   $ 64  
2011    55     65 (c)       66 (d)   54  
2010    37     42 (b) $ 7 (b) (e)   31     55 (b)
                     
PPL Energy Supply                    
2012  $ 15   $ 12 (c)     $ 4   $ 23  
2011    20     14 (c)       19 (d)   15  
2010    21     1         2     20  
                     
PPL Electric                    
2012  $ 17   $ 32       $ 31   $ 18  
2011    17     33         33     17  
2010    16     30         29     17  
   Additions    
 Balance at Beginning of Period Charged to Income Charged to Other Accounts Deductions (a) Balance at End of Period
2015$2
 $—
 $—
 $1
 $1
201421
 —
 —
 19 (b) 2
201323
 1
 —
 3
 21
                     
LKE                    
2012 - Successor $ 17   $ 9       $ 7   $ 19  
2011 - Successor   17     15         15     17  
2010 - Successor       10   $ 7 (e)       17  
2010 - Predecessor   4     10         10     4  
                     
LG&E                    
2012 - Successor $ 2   $ 2       $ 3   $ 1  
2011 - Successor   2     5         5     2  
2010 - Successor       1   $ 2 (e)   1     2  
2010 - Predecessor   2     4         4     2  
                     
KU                    
2012 - Successor $ 2   $ 4       $ 4   $ 2  
2011 - Successor   6     6         10     2  
2010 - Successor       1   $ 6 (e)   1     6  
2010 - Predecessor   3     6         6     3  

(a)Primarily related to uncollectible accounts written off.
(b)Includes amounts associated with LKE activity sinceIn 2011, a wholesale customer filed for bankruptcy protection under Chapter 11 of the November 1, 2010 acquisition date.  See Note 10 for additional information related toU.S. Bankruptcy code. In 2014, Talen Energy Marketing received an insignificant amount of cash, settling the acquisition of LKE.
(c)Includes amounts related to the SMGT bankruptcy.  See Note 15 for additional information.
(d)Includes amounts related to the June 2011, FERC approved settlement agreement between PPLoutstanding administrative claim and the California ISO related to the sales made to the California ISO during the period October 2000 through June 2001 that were not paid to PPL subsidiaries.  Therefore, the receivable andtherefore, the related allowance for doubtfulreserve balance was offset against the accounts were reversed and the settlement recorded.receivable balance.
(e)Primarily related to capital projects, thus the provision was recorded as an adjustment to construction work in progress.

Cash(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Cash Equivalents

All highly liquid debt instruments purchasedinvestments with original maturities of three months or less are considered to be cash equivalents.

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Restricted Cash and Cash Equivalents

Bank deposits and other cash equivalents that are restricted by agreement or that have been clearly designated for a specific purpose are classified as restricted cash and cash equivalents. The change in restricted cash and cash equivalents is reported as an investing activity on the Statements of Cash Flows. On the Balance Sheets, the current portion of restricted cash and cash

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equivalents is shown as "Restricted cash and cash equivalents" for PPL and PPL Energy Supply and included in "Other current assets" for PPL Electric, LKE, LG&E and KU while the noncurrent portion is included in "Other noncurrent assets" for all Registrants.  assets."

At December 31, the balances of restricted cash and cash equivalents included the following.

     PPL PPL Energy Supply PPL Electric LKE LG&E
     2012  2011  2012  2011  2012  2011  2012  2011  2012  2011 
                                  
Margin deposits posted to                              
 counterparties $ 43  $ 137  $ 43  $ 137                   
Cash collateral posted to                              
 counterparties   32    29              $ 32  $ 29  $ 32  $ 29 
Low carbon network fund (a)   14    9                         
Captive insurance reserves (b)   6    6                         
Funds deposited with a trustee (c)   13    12        $ 13  $ 12             
Ironwood debt service reserves   17       17                      
Other   10    16    3    8       1             
  Total $ 135  $ 209  $ 63  $ 145  $ 13  $ 13  $ 32  $ 29  $ 32  $ 29 
 2015 2014
Margin deposits posted to counterparties$91
 $175
Ironwood debt service reserves15
 17
Other—
 1
 $106
 $193

(a)Funds received by WPD, which are to be spent on approved initiatives to support a low carbon environment.
(b)Funds required by law to be held by WPD's captive insurance company to meet claims.
(c)Funds deposited with a trustee to defease PPL Electric's 1945 First Mortgage Bonds.
Fair Value Measurements

Fair Value Measurements (PPL, PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU)

The Registrants valuevalues certain financial and nonfinancial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to price risk management assets and liabilities, investments in securities including investments in the NDT funds and defined benefit plans, and cash and cash equivalents. PPL and its subsidiaries use,Talen Energy uses, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability.

These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.

The Registrants classifyTalen Energy classifies fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:

·
Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

·
Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability.

·
Level 3 -Level 3 - unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value.

Assessing the significance of a particular input requires judgment that considers factors specific to the asset or liability. As such, the Registrants'Talen Energy's assessment of the significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy.
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Investments

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Generally, the original maturity date of an investment and management's intent and ability to sell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for other than current operations or are clearly designated for expenditure in the acquisition or construction of noncurrent assets or for the liquidation of long-term debts, are classified as long-term.

Short-term Investments

Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and equal to or less than a year, as well as investments with original maturities of greater than a year that management has the ability and intent to sell within a year, are included in "Short-term investments" or "Other current assets" on the Balance Sheets.


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Investments in Debt and Equity Securities

Investments in debt securities are classified as held-to-maturity and measured at amortized cost when there is an intent and ability to hold the securities to maturity. Debt and equity securities held principally to capitalize on fluctuations in their value with the intention of selling them in the near-term are classified as trading. All other investments in debt and equity securities are classified as available-for-sale. Both trading and available-for-sale securities are carried at fair value. The specific identification method is used to calculate realized gains and losses on debt and equity securities. Any unrealized gains and losses on trading securities are included in earnings.

The criteria for determining whether a decline in fair value of a debt security is other than temporary and whether the other-than-temporary impairment is recognized in earnings or reported in OCI require that when a debt security is in an unrealized loss position and:

·there is an intent or a requirement to sell the security before recovery, the other-than-temporary impairment is recognized currently in earnings; or
·there is no intent or requirement to sell the security before recovery, the portion of the other-than-temporary impairment that is considered a credit loss, if any, is recognized currently in earnings and the remainder of the other-than-temporary impairment is reported in OCI, net of tax; or
·there is no intent or requirement to sell the security before recovery and there is no credit loss, the unrealized loss is reported in OCI, net of tax.

Unrealized gains and losses on available-for-sale equity securities are reported, net of tax, in OCI. When an equity security's decline in fair value below amortized cost is determined to be an other-than-temporary impairment, the unrealized loss is recognized currently in earnings. See Notes 1814 and 2319 for additional information on investments in debt and equity securities.

Equity Method Investment(PPL, LKE and KU)

Investments in entities over which PPL, LKE and KU have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting and are reported in "Other Investments" on PPL's Balance Sheet and in "Investments" on LKE's and KU's Balance Sheets.  In accordance with the accounting guidance for equity method investments, the recoverability of the investment is periodically assessed.  If an identified event or change in circumstances requires an impairment evaluation, the fair value of the investment is assessed.  The difference between the carrying amount of the investment and its estimated fair value is recognized as an impairment loss when the loss in value is deemed other-than-temporary and such loss is included in "Other-Than-Temporary Impairments" on the Statements of Income.

KU owns 20% of the common stock of EEI, which is accounted for as an equity method investment.  KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment.  During 2012, KU recorded gains (losses) of $(8) million from its share of EEI's operating results.  In December 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred.  KU recorded an impairment charge of $25 million ($15 million, after-tax) which reduced the investment balance to zero, the estimated fair value at December 31, 2012.  See Note 18 for additional information.           
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Cost Method Investment(LKE, LG&E and KU)

LG&E and KU each have an investment in OVEC, which is accounted for using the cost method.  The investment is recorded in "Investments" on the LKE and KU Balance Sheets, in "Other noncurrent assets" on the LG&E Balance Sheets and in "Other investments" on the PPL Balance Sheets.  LG&E and KU and ten other electric utilities are equity owners of OVEC.  OVEC's power is currently supplied to LG&E and KU and 11 other companies affiliated with the various owners.  LG&E and KU own 5.63% and 2.5% of OVEC's common stock.  Pursuant to a power purchase agreement, LG&E and KU are contractually entitled to their ownership percentage of OVEC's output, which is approximately 134 MW for LG&E and approximately 60 MW for KU.

LG&E's and KU's combined investment in OVEC is not significant.  The direct exposure to loss as a result of LG&E's and KU's involvement with OVEC is generally limited to the value of their investments; however, LG&E and KU may be conditionally responsible for a pro-rata share of certain OVEC obligations.  As part of PPL's acquisition of LKE, the value of the power purchase contract was recorded as an intangible asset with an offsetting regulatory liability, both of which are being amortized using the units-of-production method until March 2026, the expiration date of the agreement.  See Notes 15 and 20 for additional discussion on the power purchase agreement.          

Long-Lived and Intangible Assets

Property, Plant and Equipment

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

PP&E is recorded at original cost, unless impaired. PP&E acquired in a business combinationcombinations is recorded at fair value at the time of acquisition.acquisition, which establishes its original cost. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. Original cost for constructed assets includes material, labor, contractor costs, certain overheads and financing costs, where applicable. The cost of repairs and minor replacements are charged to expense as incurred. The Registrants record costsCosts associated with planned major maintenance projects are recorded in the period in which the costs are incurred. No costs associated with planned major maintenance projects are accrued in advance of the period in which the work is performed.  LG&E and KU accrue costs of removal net of estimated salvage value through depreciation, which is included in the calculation of customer rates over the assets' depreciable lives in accordance with regulatory practices.  Cost of removal amounts accrued through depreciation rates are accumulated as a regulatory liability until the removal costs are incurred.  See "Asset Retirement Obligations" below and Note 6 for additional information.

(PPL and PPL Energy Supply)

The original cost for the PP&E acquired in the Ironwood Acquisition is its fair value on April 13, 2012.  See Note 10 for additional information on the acquisition.

(PPL)

The original cost for the PP&E acquired in the WPD Midlands acquisition is its fair value on April 1, 2011, which approximated RAV as of the acquisition date.  See Note 10 for additional information on the acquisition.

(PPL, PPL Electric, LKE and KU)

AFUDC is capitalized as part of the construction costs for cost-based rate-regulated projects for which a return on such costs is recovered after the project is placed in service.  The debt component of AFUDC is credited to "Interest Expense" and the equity component is credited to "Other Income (Expense) - net" on the Statements of Income.  LKE and KU have not recorded significant AFUDC as a return has been provided during the construction period for most projects.

(PPL and PPL Energy Supply)

Nuclear fuel-related costs, including fuel, conversion, enrichment, fabrication and assemblies, are capitalized as PP&E. Such costs are amortized as the fuel is spent using the units-of-production method and included in "Fuel" on the Statements of Income.  PPL

Talen Energy Supply capitalizes interest costs as part of construction costs.

Capitalized interest excluding AFUDCwas as follows for PPL, is as follows.the years ended December 31.
 2015 2014 2013
 $20
 $23
 $37
           
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     PPL
  PPL Energy Supply
       
2012  $ 53  $ 47 
2011    51    47 
2010    30    33 

Depreciation

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Depreciation is recorded over the estimated useful lives of property using various methods includingprimarily the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant portion of an operating unit that was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income, unless otherwise required by regulators.income.

Following are theThe weighted-average rates of depreciation were 3.18% and 3.28% at December 31.31, 2015 and 2014.

  2012 
     PPL            
     Energy PPL        
  PPL Supply Electric LKE LG&E KU
                    
Regulated utility plant   3.12       2.57     4.39    4.91    4.06 
Non-regulated PP&E - Generation   3.05    3.05              
  2011 
     PPL            
     Energy PPL        
  PPL Supply Electric LKE LG&E KU
                    
Regulated utility plant   3.03       2.49     4.54    5.11    4.17 
Non-regulated PP&E - Generation   2.88    2.88              

(PPL, LKE, LG&E and KU)

The KPSC approved new lower depreciation rates for LG&E and KU as part of the rate-case settlement agreement reached in November 2012.  The new rates became effective January 1, 2013 and will result in lower depreciation of approximately $19 million ($9 million for LG&E and $10 million for KU) in 2013, exclusive of net additions to PP&E.

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Goodwill and Other Intangible Assets

Goodwill represents the excess of the purchase price paid over the fair value of the identifiable net assets acquired in a business combination.

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Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed or otherwise used. Costs incurred to obtain an initial license and renew or extend terms of licenses are capitalized as intangible assets.

When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, PPLTalen Energy and its subsidiaries consider the expected use of the asset; the expected useful life of other assets to which the useful life of the intangible asset may relate; legal, regulatory, or contractual provisions that may limit the useful life; the company's historical experience as evidence of its ability to support renewal or extension; the effects of obsolescence, demand, competition, and other economic factors; and the level of maintenance expenditures required to obtain the expected future cash flows from the asset.

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PPLTalen Energy accounts for emission allowances and PPL Energy Supply account for RECsRGGI emission credits (RGGI credits) as intangible assets. PPL and PPLTalen Energy Supply buy and/or sell RECs and also create RECs through owned renewable energy generation facilities.  In any period, PPL and PPL Energy Supply can be a net purchaser or seller of RECs depending on their contractual obligations to purchase or deliver RECs and the production of RECs from their renewable energy generation facilities.  The carrying value of RECs created from their renewable energy generation facilities is initially recorded at zero value and purchased RECs are initially recorded based on their purchase price.  When RECs are consumed to satisfy an obligation to deliver RECs to meet a state's Renewable Portfolio Standard Obligation or when RECs are sold to third parties, they are removed from the Balance Sheet at their weighted-average carrying value.  Since the economic benefits of RECs are not diminished until they are consumed, RECs are not amortized; rather, they are expensed when consumed or a gain or loss is recognized when sold.  Such expense is included in "Energy purchases" on the Statements of Income.  Gains and losses on the sale of RECs are included in "Other operation and maintenance" on the Statements of Income.

PPL, PPL Energy Supply, LKE, LG&E and KU account for emission allowances as intangible assets.  PPL, PPL Energy Supply, LKE, LG&E and KU are allocated emission allowances by states based on theirits generation facilities' historical emissions experience, and havehas purchased emission allowances generally or RGGI credits when it is expected that additional allowances or RGGI credits will be needed. The carrying value of allocated emission allowances is initially recorded at zero value and purchased allowances and RGGI emissions credits are initially recorded based on their purchase price. When consumed or sold, emission allowances and RGGI credits are removed from the Balance Sheet at their weighted-average carrying value. Since the economic benefits of emission allowances and RGGI credits are not diminished until they are consumed, emission allowances and RGGI credits are not amortized; rather, they are expensed when consumed or a gain or loss is recognized when sold. Such expense is included in "Fuel" on the Statements of Income. Gains and losses on the sale of emission allowances and RGGI credits are included in "Other operation"Operation and maintenance" on the Statements of Income.

Asset Impairment (Excluding Investments)

The Registrants reviewTalen Energy reviews long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or changes in circumstances indicate carrying amounts may not be recoverable.  See Note 18 for a discussion of impairments related to certain intangible assets.

A long-lived asset classified as held and used is impaired when the carrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value. See Note 15Notes 14 and 16 for a discussion of the Corette coal-fired plant in Montana which was determined to not be impaired.an impairment of an asset classified as held and used.

A long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell. See Notes 914 and 1816 for a discussion of impairment charges recorded associated with long-lived assetsimpairments of an asset group initially classified as held for sale.sale at acquisition and subsequently reclassified as held and used.

PPL, PPLTalen Energy Supply, LKE, LG&E and KU reviewreviews goodwill for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the unit's fair value. Additionally, goodwill must be tested for impairment in circumstances when a portion of goodwill has been allocated to a business to be disposed of.  PPL's, PPL Energy Supply's, LKE's, LG&E's and KU'sdisposed. Talen Energy's reporting units are at the operating segment level.

Talen Energy may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if management concludes it is more likely than not that the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.

If the carrying amount of the reporting unit, including goodwill, exceeds its fair value, the implied fair value of goodwill must be calculated in the same manner as goodwill in a business combination. The fair value of a reporting unit is allocated to all assets and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, goodwill is written down to its implied fair value.

The goodwill recognized upon the acquisition of LKE, although entirely recorded at LG&E and KU, was assigned for impairment testing by PPL to its reporting units expected to benefit from the acquisition, which were the Kentucky Regulated segment and the Supply segment.  The goodwill recognized upon the acquisition of WPD Midlands was assigned for impairment testing by PPL to its U.K. Regulated segment.  See Note 1016 for additional information regardingon a goodwill impairment recorded in the acquisition.third quarter of 2015, which fully impaired Talen Energy's previously recognized goodwill.

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Asset Retirement Obligations

PPL, PPLTalen Energy Supply, LKE, LG&E and KU tested the goodwill of all of their reporting units for impairment in the fourth quarter of 2012 and no impairment was recognized.
257
Asset Retirement Obligations

PPL and its subsidiaries recordrecords liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and offset with an increase in the value of the capitalized asset, which is depreciated over the asset's useful life. Until the obligation is settled, the liability is increased through the recognition of accretion expense classified within "Operation and maintenance" on the Statements of Incometo reflect changes in the obligation due to the passage of time through the recognition of accretion expense classified within "Other operation and maintenance" on the Statements of Income.  The accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact.  The regulatory asset created by the regulatory credit is relieved when the ARO is settled.time.

Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset. See Note 2118 for additional information on AROs.

CompensationFair Value Measurements

Talen Energy values certain financial and Benefitsnonfinancial assets and liabilities at fair value. Generally, the most significant fair value measurements relate to price risk management assets and liabilities, investments in securities including investments in the NDT funds and defined benefit plans, and cash and cash equivalents. Talen Energy uses, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability.

These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.

Talen Energy classifies fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement is based on the lowest level input that is significant to the fair value measurement in its entirety. The three levels of the fair value hierarchy are as follows:

Level 1Defined Benefits(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and KU)volume to provide pricing information on an ongoing basis.

Certain PPL subsidiaries sponsor various defined benefit pension andLevel 2 - inputs other postretirement plans.  Anthan quoted prices included within Level 1 that are either directly or indirectly observable for substantially the full term of the asset or liability.

Level 3 -unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability is recordedat fair value.

Assessing the significance of a particular input requires judgment that considers factors specific to recognize the funded statusasset or liability. As such, Talen Energy's assessment of all defined benefit plans withthe significance of a particular input may affect how the assets and liabilities are classified within the fair value hierarchy.

Investments

Generally, the original maturity date of an offsetting entryinvestment and management's intent and ability to OCIsell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for other than current operations or are clearly designated for expenditure in the acquisition or construction of noncurrent assets or for LG&E, KUthe liquidation of long-term debts, are classified as long-term.

Short-term Investments

Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and PPL Electric,equal to regulatory assets or liabilities.  Consequently,less than a year, as well as investments with original maturities of greater than a year that management has the funded status of all defined benefit plans is fully recognizedability and intent to sell within a year, are included in "Other current assets" on the Balance Sheets.


The expected return
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Investments in Debt and Equity Securities

Investments in debt securities are classified as held-to-maturity and measured at amortized cost when there is an intent and ability to hold the securities to maturity. Debt and equity securities held principally to capitalize on plan assets is determined based on a market-related value of plan assets, which is calculated by rolling forward the prior year market-relatedfluctuations in their value with contributions, disbursementsthe intention of selling them in the near-term are classified as trading. All other investments in debt and long-term expected return on investments.  One-fifth of the difference between the actual valueequity securities are classified as available-for-sale. Both trading and the expected valueavailable-for-sale securities are carried at fair value. The specific identification method is added (or subtracted if negative)used to the expected value to determine the new market-related value.

PPL uses an accelerated amortization method for the recognition ofcalculate realized gains and losses for its defined benefit pension plans.  Under the accelerated method, actuarialon debt and equity securities. Any unrealized gains and losses on trading securities are included in excessearnings.

The criteria for determining whether a decline in fair value of 30%a debt security is other than temporary and whether the other-than-temporary impairment is recognized in earnings or reported in OCI require that when a debt security is in an unrealized loss position and:

there is an intent or a requirement to sell the security before recovery, the other-than-temporary impairment is recognized currently in earnings; or
there is no intent or requirement to sell the security before recovery, the portion of the plan's projected benefit obligation are amortized onother-than-temporary impairment that is considered a straight-line basis over one-halfcredit loss, if any, is recognized currently in earnings and the remainder of the expected average remaining serviceother-than-temporary impairment is reported in OCI, net of active plan participants.  Actuarialtax.

Unrealized gains and losses on available-for-sale equity securities are reported, net of tax, in OCI. When an equity security's decline in fair value below cost is determined to be an other-than-temporary impairment, the unrealized loss is recognized currently in earnings. See Notes 14 and 19 for additional information on investments in debt and equity securities.

Long-Lived and Intangible Assets

Property, Plant and Equipment

PP&E is recorded at original cost, unless impaired. PP&E acquired in business combinations is recorded at fair value at the time of acquisition, which establishes its original cost. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. Original cost for constructed assets includes material, labor, contractor costs, certain overheads and financing costs, where applicable. The cost of repairs and minor replacements are charged to expense as incurred. Costs associated with planned major maintenance projects are recorded in the period in which the costs are incurred. No costs associated with planned major maintenance projects are accrued in advance of the period in which the work is performed.

Nuclear fuel-related costs, including fuel, conversion, enrichment, fabrication and assemblies, are capitalized as PP&E. Such costs are amortized as the fuel is spent using the units-of-production method and included in "Fuel" on the Statements of Income.

Talen Energy capitalizes interest costs as part of construction costs. Capitalized interest was as follows for the years ended December 31.
 2015 2014 2013
 $20
 $23
 $37
Depreciation

Depreciation is recorded over the estimated useful lives of property using primarily the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant portion of an operating unit that was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income.

The weighted-average rates of depreciation were 3.18% and 3.28% at December 31, 2015 and 2014.

Goodwill and Other Intangible Assets

Goodwill represents the excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basispurchase price paid over the expected average remaining service period of active plan participants.

See Note 13 for a discussion of defined benefits.

Stock-Based Compensation

(PPL, PPL Energy Supply, PPL Electric and LKE)

PPL has several stock-based compensation plans for purposes of granting stock options, restricted stock, restricted stock units and performance units to certain employees as well as stock units and restricted stock units to directors.  PPL grants most stock-based awards in the first quarter of each year.  PPL and its subsidiaries recognize compensation expense for stock-based awards based on the fair value method.  Stock options that vest in installments are valued as a single award.  PPL grants stock options with an exercise price that is not less than the fair value of PPL's common stockthe identifiable net assets acquired in a business combination.

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Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the datepattern in which the economic benefits of grant.  See Note 12the intangible assets are consumed or otherwise used. Costs incurred to obtain an initial license and renew or extend terms of licenses are capitalized as intangible assets.

When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, Talen Energy and its subsidiaries consider the expected use of the asset; the expected useful life of other assets to which the useful life of the intangible asset may relate; legal, regulatory, or contractual provisions that may limit the useful life; the company's historical experience as evidence of its ability to support renewal or extension; the effects of obsolescence, demand, competition, and other economic factors; and the level of maintenance expenditures required to obtain the expected future cash flows from the asset.

Talen Energy accounts for a discussionemission allowances and RGGI emission credits (RGGI credits) as intangible assets. Talen Energy is allocated emission allowances by states based on its generation facilities' historical emissions experience, and has purchased emission allowances generally or RGGI credits when it is expected that additional allowances or RGGI credits will be needed. The carrying value of stock-based compensation.  All awardsallocated emission allowances is initially recorded at zero value and purchased allowances and RGGI emissions credits are initially recorded as equitybased on their purchase price. When consumed or sold, emission allowances and RGGI credits are removed from the Balance Sheet at their weighted-average carrying value. Since the economic benefits of emission allowances and RGGI credits are not diminished until they are consumed, emission allowances and RGGI credits are not amortized; rather, they are expensed when consumed or a liability on the Balance Sheets.  Stock-based compensationgain or loss is primarilyrecognized when sold. Such expense is included in "Other operation and maintenance""Fuel" on the Statements of Income. Stock-based compensation expense for PPL Energy Supply, PPL ElectricGains and LKE includes an allocationlosses on the sale of PPL Services' expense.

Other

Debt Issuance Costs(PPL, PPL Energy Supply, PPL Electric, LKE, LG&Eemission allowances and KU)

Debt issuance costsRGGI credits are deferred and amortized over the term of the related debt using the interest method or another method, generally straight-line, if the results obtained are not materially different than those that would result from the interest method.
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Income Taxes

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

PPL and its domestic subsidiaries file a consolidated U.S. federal income tax return.  Prior to PPL's acquisition of LKE, LKE and its subsidiaries were included in E.ON US Investments Corp.'s consolidated U.S. federal income tax return.

Significant management judgment is required in developing the Registrants' provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns"Operation and the determination of deferred tax assets, liabilities and valuation allowances.

Significant management judgment is also required to determine the amount of benefit to be recognized in relation to an uncertain tax position.  The Registrants use a two-step process to evaluate tax positions.  The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained.  This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position.  The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion.  The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%.  The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements of the Registrants in future periods.

Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, as well as the tax effects of net operating losses and tax credit carryforwards.

The Registrants record valuation allowances to reduce deferred tax assets to the amounts that are more likely than not to be realized.  The Registrants consider the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies in initially recording and subsequently reevaluating the need for valuation allowances.  If the Registrants determine that they are able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made.  Likewise, if the Registrants determine that they are not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made.

The Registrants defer investment tax credits when the credits are utilized and amortize the deferred amounts over the average lives of the related assets.

The Registrants recognize interest and penalties in "Income Taxes" on their Statements of Income.

See Note 5 for additional discussion regarding income taxes.

(PPL, PPL Electric, LKE, LG&E and KU)

The provision for PPL, PPL Electric, LKE, LG&E and KU's deferred income taxes for regulated assets is based upon the ratemaking principles reflected in rates established by the regulators.  The difference in the provision for deferred income taxes for regulated assets and the amount that otherwise would be recorded under GAAP is deferred and included on the Balance Sheet in noncurrent "Regulatory assets" or "Regulatory liabilities."

(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The income tax provision for PPL Energy Supply, PPL Electric, LKE, LG&E and KU is calculated in accordance with an intercompany tax sharing agreement which provides that taxable income be calculated as if PPL Energy Supply, PPL Electric, LKE, LG&E, KU and any domestic subsidiaries each filed a separate return.  Tax benefits are not shared between companies.  The entity that generates a tax benefit is the entity that is entitled to the tax benefit.  The effect of PPL filing a consolidated tax return is taken into account in the settlement of current taxes and the recognition of deferred taxes.  At December 31, the following intercompany tax receivables (payables) were recorded.         
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  2012  2011 
       
PPL Energy Supply $ (38) $ (50)
PPL Electric   22    22 
LKE   (12)   3 
LG&E   5    4 
KU   (15)   5 

Taxes, Other Than Income(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The Registrants present sales taxes in "Other current liabilities" and PPL presents value-added taxes in "Taxes" on the Balance Sheets.  These taxes are not reflected on the Statements of Income.  See Note 5 for details on taxes included in "Taxes, other than income"maintenance" on the Statements of Income.

LeasesAsset Impairment (Excluding Investments)

(PPL, PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU)reviews long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or changes in circumstances indicate carrying amounts may not be recoverable.

The Registrants evaluate whether arrangements entered into contain leases for accounting purposes.A long-lived asset classified as held and used is impaired when the carrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value. See Note 11Notes 14 and 16 for a discussion of arrangements under which PPL Energy Supply, LG&Ean impairment of an asset classified as held and KU are lessees for accounting purposes.          used.

Fuel, MaterialsA long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell. See Notes 14 and Supplies16 for a discussion of impairments of an asset group initially classified as held for sale at acquisition and subsequently reclassified as held and used.

(PPL, PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU)reviews goodwill for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the unit's fair value. Additionally, goodwill must be tested for impairment in circumstances when a portion of goodwill has been allocated to a business to be disposed. Talen Energy's reporting units are at the operating segment level.

Fuel, natural gas stored undergroundTalen Energy may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and materialstest goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and supplies are valued at the lowerassessment results in a determination that it is not more likely than not that the fair value of cost or market usinga reporting unit is less than the average cost method.  Fuel costs for electric generation are charged to expense as used.  For LG&E, natural gas supply costs are charged to expense as delivered tocarrying amount, the distribution system.  See Note 6 for further discussiontwo-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if management concludes it is more likely than not that the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.

If the carrying amount of the fuel adjustment clause and gas supply clause.
(PPL, PPL Energy Supply, LKE, LG&E and KU)

"Fuel, materials and supplies" onreporting unit, including goodwill, exceeds its fair value, the Balance Sheets consistedimplied fair value of goodwill must be calculated in the following at December 31.         

     PPL PPL Energy Supply LKE LG&E KU
     2012  2011  2012  2011  2012  2011  2012  2011  2012  2011 
                                  
Fuel $ 284  $ 246  $ 135  $ 96  $ 149  $ 150  $ 61  $ 53  $ 88  $ 97 
Natural gas stored underground (a)   50    73    8    20    42    53    42    53       
Materials and supplies   339    335    184    182    85    80    39    36    46    44 
    $ 673  $ 654  $ 327  $ 298  $ 276  $ 283  $ 142  $ 142  $ 134  $ 141 

(a)  The majority of LKE's and LG&E's natural gas stored underground is held to serve native load.  The majority of PPL Energy Supply's natural gas stored underground is available for resale.

Guarantees(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Generally, the initial measurementsame manner as goodwill in a business combination. The fair value of a guarantee liabilityreporting unit is allocated to all assets and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of the guarantee atreporting unit over the amounts assigned to its inception.  However, there are certain guarantees excluded fromassets and liabilities is the scopeimplied fair value of accounting guidance and other guarantees that are not subjectgoodwill. If the implied fair value of goodwill is less than the carrying amount, goodwill is written down to the initial recognition and measurement provisions of accounting guidance that only require disclosure.  its implied fair value.

See Note 1516 for further discussioninformation on a goodwill impairment recorded in the third quarter of recorded and unrecorded guarantees.         2015, which fully impaired Talen Energy's previously recognized goodwill.

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Asset Retirement Obligations

Treasury Stock(PPLTalen Energy records liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and PPL Electric)

PPL and PPL Electric restore all sharesoffset with an increase in the value of common stock acquired to authorized but unissued shares of common stock upon acquisition.

Foreign Currency Translation and Transactions(PPL)

WPD's functional currency is the GBP,capitalized asset, which is depreciated over the local currency inasset's useful life. Until the U.K.  As such, assetsobligation is settled, the liability is increased through the recognition of accretion expense classified within "Operation and liabilities are translated to U.S. dollars at the exchange rates on the date of consolidation and related revenues and expenses are translated at average exchange rates prevailing during the period included in PPL's results of operations.  Adjustments resulting from foreign currency translation are recorded in OCI.
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Gains or losses relating to foreign currency transactions are recognized in "Other Income (Expense) - net"maintenance" on the Statements of Income.  See Note 17 for additional information.Incometo reflect changes in the obligation due to the passage of time.

New Accounting Guidance Adopted(PPL, PPL Energy Supply, PPL Electric, LKE, LG&EEstimated ARO costs and KU)settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset. See Note 18 for additional information on AROs.

Fair Value Measurements

Effective January 1, 2012,Talen Energy values certain financial and nonfinancial assets and liabilities at fair value. Generally, the Registrants prospectively adopted accounting guidancemost significant fair value measurements relate to price risk management assets and liabilities, investments in securities including investments in the NDT funds and defined benefit plans, and cash and cash equivalents. Talen Energy uses, as appropriate, a market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models) and/or a cost approach (generally, replacement cost) to measure the fair value of an asset or liability.

These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that was issuedmanagement believes are predicated on the assumptions market participants would use to clarify existingprice an asset or liability. These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.

Talen Energy classifies fair value measurements within one of three levels in the fair value hierarchy. The level assigned to a fair value measurement guidance andis based on the lowest level input that is significant to enhancethe fair value disclosures.measurement in its entirety. The additional disclosures required by this guidance include quantitative information about significant unobservable inputs used for Level 3 measurements, qualitative information about the sensitivity of recurring Level 3 measurements, information about any transfers between Levels 1 and 2three levels of the fair value hierarchy are as follows:

Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that are accessible at the measurement date. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information about whenon an ongoing basis.

Level 2 - inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for substantially the currentfull term of the asset or liability.

Level 3 -unobservable inputs that management believes are predicated on the assumptions market participants would use to measure the asset or liability at fair value.

Assessing the significance of a non-financialparticular input requires judgment that considers factors specific to the asset is different fromor liability. As such, Talen Energy's assessment of the highestsignificance of a particular input may affect how the assets and best use, andliabilities are classified within the fair value hierarchyhierarchy.

Investments

Generally, the original maturity date of an investment and management's intent and ability to sell an investment prior to its original maturity determine the classification of investments as either short-term or long-term. Investments that would otherwise be classified as short-term, but are restricted as to withdrawal or use for assets and liabilities whose fair value is disclosed onlyother than current operations or are clearly designated for expenditure in the notesacquisition or construction of noncurrent assets or for the liquidation of long-term debts, are classified as long-term.

Short-term Investments

Short-term investments generally include certain deposits as well as securities that are considered highly liquid or provide for periodic reset of interest rates. Investments with original maturities greater than three months and equal to or less than a year, as well as investments with original maturities of greater than a year that management has the financial statements.ability and intent to sell within a year, are included in "Other current assets" on the Balance Sheets.


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Investments in Debt and Equity Securities

Investments in debt securities are classified as held-to-maturity and measured at amortized cost when there is an intent and ability to hold the securities to maturity. Debt and equity securities held principally to capitalize on fluctuations in their value with the intention of selling them in the near-term are classified as trading. All other investments in debt and equity securities are classified as available-for-sale. Both trading and available-for-sale securities are carried at fair value. The specific identification method is used to calculate realized gains and losses on debt and equity securities. Any unrealized gains and losses on trading securities are included in earnings.

The adoptioncriteria for determining whether a decline in fair value of this standard resulteda debt security is other than temporary and whether the other-than-temporary impairment is recognized in earnings or reported in OCI require that when a debt security is in an unrealized loss position and:

there is an intent or a requirement to sell the security before recovery, the other-than-temporary impairment is recognized currently in earnings; or
there is no intent or requirement to sell the security before recovery, the portion of the other-than-temporary impairment that is considered a credit loss, if any, is recognized currently in earnings and the remainder of the other-than-temporary impairment is reported in OCI, net of tax.

Unrealized gains and losses on available-for-sale equity securities are reported, net of tax, in OCI. When an equity security's decline in fair value below cost is determined to be an other-than-temporary impairment, the unrealized loss is recognized currently in earnings. See Notes 14 and 19 for additional disclosures but did not haveinformation on investments in debt and equity securities.

Long-Lived and Intangible Assets

Property, Plant and Equipment

PP&E is recorded at original cost, unless impaired. PP&E acquired in business combinations is recorded at fair value at the time of acquisition, which establishes its original cost. If impaired, the asset is written down to fair value at that time, which becomes the new cost basis of the asset. Original cost for constructed assets includes material, labor, contractor costs, certain overheads and financing costs, where applicable. The cost of repairs and minor replacements are charged to expense as incurred. Costs associated with planned major maintenance projects are recorded in the period in which the costs are incurred. No costs associated with planned major maintenance projects are accrued in advance of the period in which the work is performed.

Nuclear fuel-related costs, including fuel, conversion, enrichment, fabrication and assemblies, are capitalized as PP&E. Such costs are amortized as the fuel is spent using the units-of-production method and included in "Fuel" on the Statements of Income.

Talen Energy capitalizes interest costs as part of construction costs. Capitalized interest was as follows for the years ended December 31.
 2015 2014 2013
 $20
 $23
 $37
Depreciation

Depreciation is recorded over the estimated useful lives of property using primarily the straight-line, composite and group methods. When a component of PP&E that was depreciated under the composite or group method is retired, the original cost is charged to accumulated depreciation. When all or a significant impactportion of an operating unit that was depreciated under the composite or group method is retired or sold, the property and the related accumulated depreciation account is reduced and any gain or loss is included in income.

The weighted-average rates of depreciation were 3.18% and 3.28% at December 31, 2015 and 2014.

Goodwill and Other Intangible Assets

Goodwill represents the excess of the purchase price paid over the fair value of the identifiable net assets acquired in a business combination.

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Other acquired intangible assets are initially measured based on their fair value. Intangibles that have finite useful lives are amortized over their useful lives based upon the pattern in which the economic benefits of the intangible assets are consumed or otherwise used. Costs incurred to obtain an initial license and renew or extend terms of licenses are capitalized as intangible assets.

When determining the useful life of an intangible asset, including intangible assets that are renewed or extended, Talen Energy and its subsidiaries consider the expected use of the asset; the expected useful life of other assets to which the useful life of the intangible asset may relate; legal, regulatory, or contractual provisions that may limit the useful life; the company's historical experience as evidence of its ability to support renewal or extension; the effects of obsolescence, demand, competition, and other economic factors; and the level of maintenance expenditures required to obtain the expected future cash flows from the asset.

Talen Energy accounts for emission allowances and RGGI emission credits (RGGI credits) as intangible assets. Talen Energy is allocated emission allowances by states based on its generation facilities' historical emissions experience, and has purchased emission allowances generally or RGGI credits when it is expected that additional allowances or RGGI credits will be needed. The carrying value of allocated emission allowances is initially recorded at zero value and purchased allowances and RGGI emissions credits are initially recorded based on their purchase price. When consumed or sold, emission allowances and RGGI credits are removed from the Balance Sheet at their weighted-average carrying value. Since the economic benefits of emission allowances and RGGI credits are not diminished until they are consumed, emission allowances and RGGI credits are not amortized; rather, they are expensed when consumed or a gain or loss is recognized when sold. Such expense is included in "Fuel" on the Registrants.  See Note 18 for additional disclosures required by this guidance.Statements of Income. Gains and losses on the sale of emission allowances and RGGI credits are included in "Operation and maintenance" on the Statements of Income.

Testing Goodwill forAsset Impairment (Excluding Investments)

Effective January 1, 2012,Talen Energy reviews long-lived assets that are subject to depreciation or amortization, including finite-lived intangibles, for impairment when events or changes in circumstances indicate carrying amounts may not be recoverable.

A long-lived asset classified as held and used is impaired when the Registrants prospectively adopted accounting guidance which allowscarrying amount of the asset exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If impaired, the asset's carrying value is written down to its fair value. See Notes 14 and 16 for a discussion of an entityimpairment of an asset classified as held and used.

A long-lived asset classified as held for sale is impaired when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If impaired, the asset's (disposal group's) carrying value is written down to its fair value less cost to sell. See Notes 14 and 16 for a discussion of impairments of an asset group initially classified as held for sale at acquisition and subsequently reclassified as held and used.

Talen Energy reviews goodwill for impairment at the reporting unit level annually or more frequently when events or circumstances indicate that the carrying amount of a reporting unit may be greater than the unit's fair value. Additionally, goodwill must be tested for impairment in circumstances when a portion of goodwill has been allocated to a business to be disposed. Talen Energy's reporting units are at the operating segment level.

Talen Energy may elect the optioneither to firstinitially make a qualitative evaluation about the likelihood of an impairment of goodwill.goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If based on thisthe qualitative evaluation (referred to as "step zero") is elected and the assessment the entity determinesresults in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the two-step goodwillquantitative impairment test is not necessary. However, the first step of thequantitative impairment test is required if an entitymanagement concludes it is more likely than not that the fair value of a reporting unit is less than the carrying amount based on the qualitativestep zero assessment.

If the carrying amount of the reporting unit, including goodwill, exceeds its fair value, the implied fair value of goodwill must be calculated in the same manner as goodwill in a business combination. The adoptionfair value of this standard did not have a significant impactreporting unit is allocated to all assets and liabilities of that unit as if the reporting unit had been acquired in a business combination. The excess of the fair value of the reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, goodwill is written down to its implied fair value.

See Note 16 for information on a goodwill impairment recorded in the Registrants.third quarter of 2015, which fully impaired Talen Energy's previously recognized goodwill.

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Asset Retirement Obligations

2.  SegmentTalen Energy records liabilities to reflect various legal obligations associated with the retirement of long-lived assets. Initially, this obligation is measured at fair value and Related Information

(PPL)

Sinceoffset with an increase in the acquisition of LKE on November 1, 2010, PPL is organized into four segments:  Kentucky Regulated, U.K. Regulated (name change in 2012 from International Regulated to more specifically reflect the focusvalue of the segment), Pennsylvania Regulatedcapitalized asset, which is depreciated over the asset's useful life. Until the obligation is settled, the liability is increased through the recognition of accretion expense classified within "Operation and Supply.  Other than the name change for the U.K. Regulated segment, there were no other changes to this segment.  PPL's segments are split between its regulated and competitive businesses with its regulated businesses further segmented by geographic location.

The Kentucky Regulated segment consists primarily of LKE's regulated electric generation, transmission and distribution operations, primarily in Kentucky.  This segment also includes LKE's regulated distribution and sale of natural gas in Kentucky.  In addition, the Kentucky Regulated segment is allocated certain financing costs.  See Note 10 for additional information regarding the acquisition.

The U.K. Regulated segment primarily consists of the regulated electric distribution operations in the U.K.  This includes the operating results and assets of WPD Midlands since the April 1, 2011 acquisition date, recorded on a one-month lag.  The U.K. Regulated segment is also allocated certain WPD Midlands acquisition-related costs and financing costs.  See Note 10 for additional information regarding the acquisition.

The Pennsylvania Regulated segment includes the regulated electric transmission and distribution operations of PPL Electric.

The Supply segment primarily consists of the domestic energy marketing and trading activities, as well as the competitive generation operations of PPL Energy Supply.

The results of operations of several facilities and businesses have been classified as Discontinued Operationsmaintenance" on the Statements of Income.  Incometo reflect changes in the obligation due to the passage of time.

Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset. See Note 18 for additional information on AROs.

Compensation and Benefits

Defined Benefits

Talen Energy Supply and certain of its subsidiaries sponsor or participate in, as applicable, various qualified funded and non-qualified unfunded defined benefit pension plans and both funded and unfunded other postretirement benefit plans. Prior to the June 1, 2015 spinoff, Talen Energy participated in plans sponsored by PPL. An asset or liability is recorded with an offsetting entry to AOCI to recognize the funded status of all defined benefit plans sponsored by Talen Energy Supply and its subsidiaries. Consequently, the funded status of all sponsored defined benefit plans is fully recognized on the Balance Sheets.

The expected return on plan assets is determined based on a market-related value of plan assets, which is calculated by rolling forward the prior year market-related value with contributions, disbursements and long-term expected return on investments. One-fifth of the difference between the actual value and the expected value is added (or subtracted if negative) to the expected value to determine the new market-related value.

Talen Energy uses an accelerated amortization method for the recognition of gains and losses for its defined benefit pension plans. Under the accelerated method, actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants. Actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service period of active plan participants.

See Note 9 for additional information on these discontinued operations.  Therefore,about the plans and the accounting for defined benefits, including a discussion of the newly created pension and other postretirement benefit plans sponsored by Talen Energy Supply that replaced Talen Energy Supply's participation in similar PPL plans effective with the exceptionJune 1, 2015 spinoff.

Stock-Based Compensation

Talen Energy Corporation has stock-based compensation plans for purposes of "Net Income Attributablegranting stock options, restricted stock, restricted stock units and performance units to PPL Shareowners" the operating results from these facilitiescertain employees as well as stock units and businesses have been excluded from the income statement data tables below.
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"Corporate and Other" represents costs incurred at the corporate level that have not been allocated or assignedrestricted stock units to directors. Prior to the segments, which is presented to reconcile segment information to PPL's consolidated results.  For 2012 and 2011, there were no significant costsJune 1, 2015 spinoff Talen Energy Supply participated in this category.  For 2010, these costs represent LKE acquisition-related costs including advisory, accounting and legal fees, certain internal costs and 2010 Bridge Facility costs.

Beginningplans sponsored by PPL. Talen Energy recognizes compensation expense for stock-based awards based on the fair value method. Stock options that vest in 2013, PPL anticipates more costs to be included in the Corporate and Other category primarily due to an anticipated increase in the use of financing issued by PPL Capital Funding not directly attributable toinstallments are valued as a particular segment.  PPL's recent growth in rate-regulated businesses provides the organizationsingle award. Talen Energy Corporation grants stock options with an enhanced corporate level financing alternative, through PPL Capital Funding,exercise price that further enables PPL to support targeted credit profiles cost effectively across allis not less than the fair value of PPL's rated companies.  AsTalen Energy Corporation's common stock on the date of grant. All awards are recorded as equity or a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing by the operating companies, as appropriate.  The financing costs associated primarily with PPL Capital Funding's future securities issuances are not expected to be directly assignable or allocable to any segment and generally will be reflected in Corporate and Other beginning in 2013.

Financial data for the segments are:   

Income Statement Data 2012  2011  2010 
Revenues from external customers by product         
  Kentucky Regulated         
   Utility service (a) $ 2,759  $ 2,793  $ 493 
  U.K. Regulated         
   Utility service (a)   2,289    1,618    727 
   Energy-related businesses   47    35    34 
    Total   2,336    1,653    761 
  Pennsylvania Regulated         
   Utility service (a)   1,760    1,881    2,448 
  Supply         
   Energy (b)   4,970    5,938    4,444 
   Energy-related businesses   461    472    375 
    Total   5,431    6,410    4,819 
Total   12,286    12,737    8,521 
              
Intersegment electric revenues         
  Pennsylvania Regulated   3    11    7 
  Supply (c)   79    26    320 
              
Depreciation         
  Kentucky Regulated   346    334    49 
  U.K. Regulated   279    218    117 
  Pennsylvania Regulated   160    146    136 
  Supply   315    262    254 
Total   1,100    960    556 
              
Amortization (d)         
  Kentucky Regulated   27    27    
  U.K. Regulated   15    83    13 
  Pennsylvania Regulated   18    7    (22)
  Supply   126    137    148 
  Corporate and Other         74 
Total   186    254    213 
              
Unrealized (gains) losses on derivatives and other hedging activities (b)         
  Kentucky Regulated      (2)   1 
  Supply   27    (312)   541 
Total   27    (314)   542 
              
Interest income         
  U.K. Regulated   3    4    2 
  Pennsylvania Regulated   1    1    4 
  Supply   1    2    2 
Total   5    7    8 
              
Interest Expense         
  Kentucky Regulated   219    217    55 
  U.K. Regulated   421    391    135 
  Pennsylvania Regulated   99    98    99 
  Supply   222    192    224 
  Corporate and Other         80 
Total   961    898    593 
262
  2012  2011  2010 
Income from Continuing Operations Before Income Taxes         
  Kentucky Regulated   263    349    40 
  U.K. Regulated   953    358    261 
  Pennsylvania Regulated   204    257    192 
  Supply (b)   662    1,237    860 
  Corporate and Other         (114)
Total   2,082    2,201    1,239 
              
Income Taxes (e)         
  Kentucky Regulated   80    127    16 
  U.K. Regulated   150    33    
  Pennsylvania Regulated   68    68    57 
  Supply   247    463    228 
  Corporate and Other         (38)
Total   545    691    263 
              
Deferred income taxes and investment tax credits (f)         
  Kentucky Regulated   136    218    51 
  U.K. Regulated   26    (39)   17 
  Pennsylvania Regulated   114    106    198 
  Supply   150    299    (15)
Total   426    584    251 
              
Net Income Attributable to PPL Shareowners         
  Kentucky Regulated   177    221    26 
  U.K. Regulated   803    325    261 
  Pennsylvania Regulated   132    173    115 
  Supply (b)   414    776    612 
  Corporate and Other         (76)
 Total $ 1,526  $ 1,495  $ 938 
              
Cash Flow Data  2012   2011   2010 
Expenditures for long-lived assets         
  Kentucky Regulated $ 768  $ 465  $ 152 
  U.K. Regulated   1,016    862    281 
  Pennsylvania Regulated   633    490    411 
  Supply   736    739    795 
Total $ 3,153  $ 2,556  $ 1,639 

   As of December 31,
   2012  2011 
Balance Sheet Data      
Total Assets      
 Kentucky Regulated $ 10,670  $ 10,229 
 U.K. Regulated   14,073    13,364 
 Pennsylvania Regulated   6,023    5,610 
 Supply   12,868    13,445 
Total $ 43,634  $ 42,648 

  2012  2011  2010 
Geographic Data         
Revenues from external customers         
  U.S. $ 9,950  $ 11,084  $ 7,760 
  U.K.   2,336    1,653    761 
Total $ 12,286  $ 12,737  $ 8,521 

   As of December 31,
   2012  2011 
Long-Lived Assets      
 U.S. $ 20,776  $ 19,129 
 U.K.   9,951    8,996 
Total $ 30,727  $ 28,125 

(a)
See Note 1 for additional information on Utility Revenue.
(b)Includes unrealized gains and losses from economic activity.  See Note 19 for additional information.
(c)See "PLR Contracts/Purchase of Accounts Receivable" and "NUG Purchases" in Note 16 for a discussion of the basis of accounting between reportable segments.
(d)Represents non-cash expense items that include amortization of nuclear fuel, regulatory assets, debt discounts and premiums, debt issuance costs, emission allowances and RECs.
(e)Represents both current and deferred income taxes, including investment tax credits.
(f)Represents a non-cash expense item that is also included in "Income Taxes."
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(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

PPL Energy Supply, PPL Electric, LKE, LG&E and KU each operate within a single reportable segment.

3.  Preferred Securities

(PPL)

PPL classifies preferred securities of subsidiaries as "Noncontrolling interests"liability on the Balance Sheets and related dividend requirements of $4 million for 2012, $16 million for 2011 and $17 million for 2010 have beenSheets. Stock-based compensation is primarily included in "Net Income Attributable to Noncontrolling Interests""Operation and maintenance" on the Statements of Income. InStock-based compensation expense for periods prior to the June 2012,1, 2015 spinoff also includes an allocation of PPL Electric redeemed all of its Preference Stock at par value, without premium ($250 million in the aggregate).

Preferred Stock

PPL is authorized to issue up to 10 million shares of preferred stock.  No PPL preferred stock was issued or outstanding in 2012, 2011, or 2010.

(PPL Electric)

PPL Electric is authorized to issue up to 629,936 shares of 4-1/2% Preferred Stock and 10 million shares of series preferred stock.  In April 2010, PPL Electric redeemed all of its outstanding preferred stock (247,524 shares of 4-1/2% Preferred Stock and 257,665 shares of four series of preferred stock), with a par value in the aggregate of $51 million, for $54 million including accumulated dividends.      

(LG&E)

LG&E is authorized to issue up to 1,720,000 shares of preferred stock at a $25 par value and 6,750,000 shares of preferred stock without par value.  LG&E had no preferred stock issued or outstanding in 2012, 2011 or 2010.

(KU)

KU is authorized to issue up to 5,300,000 shares of preferred stock without par value.  KU had no preferred stock issued or outstanding in 2012, 2011 or 2010.          

Preference Stock

(PPL Electric)

PPL Electric is authorized to issue up to 10 million shares of Preference Stock and had 2.5 million shares of 6.25% Series Preference Stock (Preference Shares) issued and outstanding at December 31, 2011 and 2010.  In June 2012, PPL Electric redeemed all 2.5 million shares of its outstanding Preference Shares, par value of $100 per share.  The price paid for the redemption was the par value, without premium ($250 million in the aggregate).

The Preference Shares were held by a bank that acted as depositary for 10 million depositary shares, each of which represented a one-quarter interest in a Preference Share.  Holders of the depositary shares were entitled to all proportional rights and preferences of the Preference Shares, including dividend, voting, redemption and liquidation rights, exercised through the bank acting as a depositary.  The Preference Shares ranked senior to PPL Electric's common stock but had no voting rights, except as provided by law, and they had a liquidation preference of $100 per share (equivalent to $25 per depositary share).
(KU)

KU is authorized to issue up to 2,000,000 shares of preference stock without par value.  KU had no preference stock issued or outstanding in 2012, 2011 or 2010.

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4.  Earnings Per Share

(PPL)

Basic EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of common shares outstanding during the period.  Diluted EPS is computed by dividing income available to PPL common shareowners by the weighted-average number of shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares as calculated using the treasury stock method.  In 2012, 2011 and 2010, these securities included stock options and performance units granted under incentive compensation plans and the Purchase Contracts associated with the 2011 and 2010 Equity Units.  For 2012, these securities also included the PPL common stock forward sale agreements.Services' expense. See Note 78 for additional information on stock-based compensation.

Taxes

Income Taxes

Talen Energy Corporation and its subsidiaries file a consolidated U.S. federal income tax return.


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Significant management judgment is required in developing Talen Energy's provision for income taxes, primarily due to the forward sale agreements.uncertainty related to tax positions taken or expected to be taken in tax returns and valuation allowances that may be required to offset deferred tax assets.

In order to determine the amount of benefit to be recognized in relation to an uncertain tax position, Talen Energy uses a two-step process to evaluate tax positions. The forward sale agreements were dilutive underfirst step requires an entity to determine whether, based on the treasury stock method for 2012 becausetechnical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the average stock pricetax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of PPL's common shares exceededall the forward sale price indicatedrelevant facts surrounding the tax position. The second step requires an entity to recognize in the forward sale agreements.

financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The Purchase Contracts are dilutive underbenefit recognized is measured at the treasury stock method if the average VWAPlargest amount of PPL common stock forbenefit that has a certain periodlikelihood of realization, upon settlement, that exceeds approximately $30.99 and $28.80 for the 2011 and 2010 Purchase Contracts.50%. The 2010 Purchase Contracts were dilutive for 2012 and 2011.  Subject to antidilution adjustments at December 31, 2012, the maximum numberamounts ultimately paid upon resolution of shares issuable to settle the Purchase Contracts was 93.8 million shares, including 86.6 million shares that could be issued under standard provisions of the Purchase Contracts and 7.2 million shares that could be issued under make-whole provisions in the event of early settlement upon a Fundamental Change.  See Note 7 for additional information on the 2011 and 2010 Equity Units.

Reconciliations ofissues raised by taxing authorities may differ materially from the amounts of incomeaccrued and shares of PPL common stock (in thousands) formay materially impact the periods ended December 31 usedfinancial statements in the EPS calculation are:

     2012  2011  2010 
Income (Numerator)         
Income from continuing operations after income taxes attributable to PPL shareowners $ 1,532  $ 1,493  $ 955 
Less amounts allocated to participating securities   8    6    4 
Less issuance costs on subsidiary's preferred securities redeemed   6       
Income from continuing operations after income taxes available to PPL common shareowners $ 1,518  $ 1,487  $ 951 
             
Income (loss) from discontinued operations (net of income taxes) available to PPL         
 common shareowners $ (6) $ 2  $ (17)
             
Net income attributable to PPL shareowners $ 1,526  $ 1,495  $ 938 
Less amounts allocated to participating securities   8    6    4 
Less issuance costs on subsidiary's preferred securities redeemed   6       
Net income available to PPL common shareowners $ 1,512  $ 1,489  $ 934 
             
Shares of Common Stock (Denominator)         
Weighted-average shares - Basic EPS   580,276    550,395    431,345 
Add incremental non-participating securities:         
  Stock options and performance units   563    400    224 
  2010 Purchase Contracts   195    157    
  Forward sale agreements   592       
Weighted-average shares - Diluted EPS   581,626    550,952    431,569 
             
Basic EPS         
Available to PPL common shareowners:         
  Income from continuing operations after income taxes $ 2.62  $ 2.70  $ 2.21 
  Income (loss) from discontinued operations (net of income taxes)   (0.01)   0.01    (0.04)
  Net Income $ 2.61  $ 2.71  $ 2.17 
             
Diluted EPS         
Available to PPL common shareowners:         
  Income from continuing operations after income taxes $ 2.61  $ 2.70  $ 2.20 
  Income (loss) from discontinued operations (net of income taxes)   (0.01)      (0.03)
  Net Income $ 2.60  $ 2.70  $ 2.17 
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During 2012, PPL issued 936,218 shares of common stock related to the exercise of stock options, vesting of restricted stock and restricted stock units and conversion of stock units granted to directors under its stock-based compensation plans.  In addition, PPL issued 279,945 and 2,326,917 shares of common stock related to its ESOP and DRIP during 2012.  See Note 12 for a discussion of PPL's stock-based compensation plans.

The following stock options to purchase PPL common stock and performance units were excluded from the computations of diluted EPS for the years ended December 31 because the effect would have been antidilutive.   

(Shares in thousands) 2012  2011  2010 
          
Stock options   5,293    5,084    4,936 
Performance units   58    2    45 

5.  Income and Other Taxes

(PPL)

"Income from Continuing Operations Before Income Taxes" included the following components:

   2012  2011  2010 
           
Domestic income $ 994  $ 1,715  $ 952 
Foreign income   1,088    486    287 
 Total $ 2,082  $ 2,201  $ 1,239 
future periods.

Deferred income taxes reflect the net future tax effects of temporary differences between the carrying amounts of assets and liabilities for accounting purposes and their basis for income tax purposes, andas well as the tax effects of net operating loss carryforwards and tax credit carryforwards.  The provision

Talen Energy records valuation allowances to reduce deferred tax assets to the amounts that are more likely than not to be realized. Talen Energy considers the ability to carryback attributes, the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies in initially recording and subsequently reevaluating the need for PPL'svaluation allowances. If Talen Energy determines that it is able to realize deferred tax assets in the future in excess of recorded net deferred tax assets, adjustments to the valuation allowances increase income by reducing tax expense in the period that such determination is made. Likewise, if Talen Energy determines that it is not able to realize all or part of net deferred tax assets in the future, adjustments to the valuation allowances would decrease income by increasing tax expense in the period that such determination is made.

Talen Energy defers investment tax credits when the credits are utilized and amortizes the deferred amounts over the average lives of the related assets.

Talen Energy classifies interest and penalties from tax uncertainties in "Income Taxes" on its Statements of Income.

Talen Energy records the receipt of grants related to assets as a reduction to the book basis of the property and the related deferred income taxes as an immediate reduction to income tax expense.

The income tax provision for regulated assetsTalen Energy Supply is calculated in accordance with an intercompany tax sharing agreement which provides that taxable income be calculated as if Talen Energy Supply and liabilitiesany subsidiaries each filed a separate consolidated return. Tax benefits are not shared between companies. The entity that generates a tax benefit is based upon the ratemaking principlesentity that is entitled to the tax benefit. The effect of Talen Energy Corporation filing a consolidated tax return is taken into account in the settlement of current taxes and the recognition of deferred taxes.

Prior to the spinoff, the income tax provision for Talen Energy Supply was calculated in accordance with an intercompany tax sharing agreement with PPL, which provided that taxable income be calculated as if Talen Energy Supply, and any of PPL's domestic subsidiaries, each filed a separate consolidated return. Tax benefits were not shared between companies. The entity that generated a tax benefit was the entity that was entitled to the tax benefit. At December 31, 2014 Talen Energy Supply had a $105 million intercompany tax receivable with PPL recorded under the tax sharing agreement, which was settled prior to the spinoff from PPL.

Taxes, Other Than Income

Talen Energy presents sales taxes in "Other current liabilities." These taxes are not reflected on the Statements of Income. See Note 4 for details on taxes included in "Taxes, other than income" on the Statements of Income.

Other

Leases

Talen Energy evaluates whether arrangements entered into contain leases for accounting purposes. See Note 7 for a discussion of arrangements under which Talen Energy is a lessee for accounting purposes.

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Fuel, Materials and Supplies

Fuel, materials and supplies are valued at the lower of cost or market using the average cost method. Generally, cost is reduced to market if the value of inventory has declined and it is probable that the utility of inventory in the ordinary course of business will not be recovered through revenue earned. Fuel costs for electric generation are charged to expense as used. Materials and supplies are charged to "Operation and maintenance" on the Statements of Income as they are used for repairs and maintenance or capitalized to PP&E as they are used for capital projects.

"Fuel, materials and supplies" on the Balance Sheets consisted of the applicable jurisdiction.following at December 31.
 2015 2014
Fuel$257
 $250
Materials and supplies251
 205
Total$508
 $455

Guarantees

Generally, the initial measurement of a guarantee liability is the fair value of the guarantee at its inception. However, there are certain guarantees excluded from the scope of accounting guidance and other guarantees that are not subject to the initial recognition and measurement provisions of accounting guidance that only require disclosure. See NotesNote 11 for further discussion of recorded and unrecorded guarantees.

New Accounting Guidance Adopted

Reporting of Discontinued Operations

Effective January 1, 2015, Talen Energy prospectively adopted accounting guidance that changes the criteria for determining what should be classified as a discontinued operation and the related presentation and disclosure requirements. A discontinued operation may include a component of an entity or a group of components of an entity, or a business activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on the entity's operations and financial results when any of the following occurs: (1) the components of an entity or a group of components of an entity meets the criteria to be classified as held for sale, (2) the component of an entity or a group of components of an entity is disposed of by sale, or (3) the component of an entity or a group of components of an entity is disposed of other than by sale (for example, by abandonment or in a distribution to owners in a spinoff). In addition, the guidance provides that upon acquisition, if a business or activity meets the held for sale criteria, it is then also to be classified as a discontinued operation.

The initial adoption of this guidance did not have a significant impact on Talen Energy but will impact the amounts presented as discontinued operations and will enhance the related disclosure requirements related to future disposals or held for sale classifications.

Accounting for Measurement-Period Adjustments

Effective September 30, 2015, Talen Energy prospectively adopted accounting guidance that requires an acquirer in a business combination to recognize measurement-period adjustments in the period in which the amounts are determined, including the effect on earnings of any amounts that would have been recorded in prior periods as if the accounting would have been completed at the acquisition date. The acquirer must disclose, by line item, the portion of the adjustment recorded in the current period income statement that would have been recognized in prior periods if the adjustment had been recognized as of the acquisition date.

The guidance applies to open measurement periods as of the adoption date and therefore applies to any measurement period adjustment made for the acquisitions of RJS Power and MACH Gen. See Note 6 for additional information.


Net
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Balance Sheet Classification of Deferred Taxes

Effective December 31, 2015, Talen Energy prospectively adopted accounting guidance that requires deferred tax liabilities and assets have been recognized based on management's estimates of future taxable income forto be classified as noncurrent in the U.S. and certain foreign jurisdictions in which PPL's operations have historically been profitable.

Significant components of PPL'sbalance sheet. The prior period amounts were not retrospectively adjusted. The current requirement that deferred income tax assets and liabilities wereof a tax-paying component of an entity be offset and presented as follows:a single amount is not affected by the guidance.

2. Segment and Related Information

Prior to the spinoff transaction, Talen Energy operated within a single reportable segment. Immediately following the spinoff, Talen Energy determined that it operated in two reportable segments: East and West, primarily based on geographic location and energy market characteristics. After the completion of the MACH Gen acquisition in November 2015, management reevaluated its segment composition.

    2012  2011 
Deferred Tax Assets      
 Deferred investment tax credits $130  $113 
 Regulatory obligations  124   149 
 Accrued pension costs  276   325 
 Federal loss carryforwards  524   305 
 State loss carryforwards  305   272 
 Federal and state tax credit carryforwards  287   240 
 Foreign capital loss carryforwards  525   578 
 Foreign loss carryforwards  6   7 
 Foreign - pensions  254   74 
 Foreign - regulatory obligations  27   67 
 Foreign - other  16   21 
 Contributions in aid of construction  134   133 
 Domestic - other  239   229 
 Valuation allowances  (706)  (724)
  Total deferred tax assets  2,141   1,789 
         
Deferred Tax Liabilities      
 Domestic plant - net   3,967    3,465 
 Taxes recoverable through future rates   141    137 
 Unrealized gain on qualifying derivatives   122    331 
 Other regulatory assets   319    234 
 Reacquired debt costs   40    93 
 Foreign plant - net   937    975 
 Foreign - other      22 
 Domestic - other   66    103 
  Total deferred tax liabilities   5,592    5,360 
Net deferred tax liability $ 3,451  $ 3,571 
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At December 31, PPL had2015, Talen Energy continues to operate in two reportable segments, however with a different composition than prior to the following lossNovember 2015 MACH Gen acquisition, primarily based on geographic location. The East segment now primarily includes the generating, marketing and tax credit carryforwards.

   2012   Expiration
        
Loss carryforwards      
 Federal net operating losses $ 1,481   2028-2032
 Federal charitable contributions   19   2016-2017
 State net operating losses   5,099   2013-2032
 State capital losses   138   2013-2016
 Foreign net operating losses   27   Indefinite
 Foreign capital losses   2,282   Indefinite
        
Credit carryforwards      
 Federal investment tax credit   233   2025-2032
 Federal alternative minimum tax credit   20   Indefinite
 Federal foreign tax credit   1   2017-2022
 Federal - other   30   2016-2032
 State - other   4   2022 

Valuation allowances have been established fortrading activities in PJM, NYISO and ISO-NE. The West segment includes the amount that, more likely than not, will not be realized.  The changesgenerating, marketing and trading activities in deferred tax valuation allowances were:

     Additions       
  Balance at    Charged to     Balance
  Beginning Charged Other    at End
  of Period to Income Accounts Deductions of Period
                  
2012  $ 724  $ 18  $ 10   $ 46 (a) $ 706 
2011    464    190    112 (b)   42 (c)   724 
2010    312    221    6     75 (d)   464 

(a)
The reduction of the U.K. statutory income tax rate resulted in a reduction in deferred tax assets and the corresponding valuation allowances.  See "Reconciliation of Income Tax Expense" below for more information on the impact of the U.K. Finance Act of 2012.
(b)Primarily related to a $101 million valuation allowance thatERCOT and WECC, including the coal-fired facility, Colstrip, in Montana, which was recorded against certain deferred tax assets as a result of the 2011 acquisition of WPD Midlands.  See Note 10 for additional information on the acquisition.
(c)The reduction of the U.K. statutory income tax rate resulted in a $35 million reduction in deferred tax assets and the corresponding valuation allowances.  See "Reconciliation of Income Tax Expense" below for more information on the impact of the U.K. Finance Act of 2011.
(d)Resulting from the projected revenue increase in connection with the expiration of the Pennsylvania generation rate caps in 2010, the valuation allowance related to state net operating loss carryforwards over the remaining carryforward period was reduced by $72 million.         

PPL Global does not pay or record U.S. income taxes on the undistributed earnings of WPD, with the exception of certain financing entities, as management has determined that the earnings are indefinitely reinvested.  Historically, dividends paid by WPD have been distributions from current year's earnings.  WPD's long-term working capital forecasts and capital expenditure projections for the foreseeable future require reinvestment of WPD's undistributed earnings, and WPD would have to issue debt or access credit facilities to fund any distributions in excess of current earnings.  Additionally, U.S. long-term working capital forecasts and capital expenditure projections for the foreseeable future do not require or contemplate distributions from WPD in excess of some portion of future WPD earnings.  The cumulative undistributed earnings are included in "Earnings Reinvested" on the Balance Sheets.  The amounts considered indefinitely reinvested at December 31, 2012 and 2011 were $2.0 billion and $1.2 billion.  IfEast segment prior to the WPD undistributed earnings were remitted as dividends, PPL Global could be subject to additional U.S. taxes, net of allowable foreign tax credits.  It is not practicable to estimate the amount of additional taxes that could be payable on these foreign earnings.segment reevaluation.

DetailsSegment information for prior periods has been revised to reflect the current period presentation as the composition of the componentssegments and the measurement of segment performance has changed. Previously, net income tax expense,was used as the measure of segment performance. Beginning in June 2015, operating income, as well as the non-GAAP measures, Adjusted EBITDA and Margins, is used as a reconciliationmeasure of federal income taxes derived from statutory tax rates applied to "Income from Continuing Operations Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:segment performance.
267
     2012  2011  2010 
Income Tax Expense (Benefit)         
 Current - Federal    $ 54  $ (51)
 Current - State $ (2)   (20)   43 
 Current - Foreign   121    73    20 
   Total Current Expense (Benefit)   119    107    12 
 Deferred - Federal   553    558    358 
 Deferred - State   103    127    (82)
 Deferred - Foreign   35    (23)   (9)
   Total Deferred Expense (Benefit), excluding operating loss carryforwards   691    662    267 
             
 Investment tax credit, net - Federal   (10)   (10)   (5)
 Tax benefit of operating loss carryforwards         
  Deferred - Federal   (195)   (30)   6 
  Deferred - State   (60)   (38)   (17)
   Total Tax Benefit of Operating Loss Carryforwards   (255)   (68)   (11)
 Total income taxes from continuing operations (a) $ 545  $ 691  $ 263 
             
 Total income tax expense - Federal $ 348  $ 572  $ 308 
 Total income tax expense (benefit) - State  41    69    (56)
 Total income tax expense - Foreign   156    50    11 
   Total income taxes from continuing operations (a) $ 545  $ 691  $ 263 

"Other" primarily includes wages, benefits, services, certain insurance, rent, financing costs incurred primarily at Talen Energy, which have not been allocated or assigned to the segments and inter-company eliminations, and is presented to reconcile segment information to consolidated results.


89

Table of Contents

Financial data for the segments and reconciliation to consolidated results for the years ended December 31 are:
  East West Other Total
2015        
Revenues from external customers by product        
Energy $3,653
 $284
 $—
 $3,937
Energy-related business 544
 —
 —
 544
Total Revenues $4,197
 $284
 $—
 $4,481
         
Operating income (loss) (a) $198
 $2
 $(239) $(39)
Depreciation 327
 26
 3
 356
Amortization (b) 200
 1
 21
 222
Unrealized (gains) losses on derivatives and other hedging activities (c) (143) 24
 —
 (119)
Impairments (d) 657
 —
 —
 657
Expenditures for long-lived assets (e) 387
 39
 38
 464
Total assets (f) 11,430
 1,231
 165
 12,826
         
2014        
Revenues from external customers by product        
Energy $3,771
 $209
 $—
 $3,980
Energy-related business 601
 —
 —
 601
Total Revenues $4,372
 $209
 $—
 $4,581
         
Operating income (loss) $558
 $71
 $(232) $397
Depreciation 296
 1
 —
 297
Amortization (b) 154
 —
 9
 163
Unrealized (gains) losses on derivatives and other hedging activities (c) 35
 (31) —
 4
Expenditures for long-lived assets 400
 31
 —
 431
Total assets (f) 10,308
 160
 292
 10,760
         
2013        
Revenues from external customers by product        
Energy $3,791
 $177
 $—
 $3,968
Energy-related business 527
 —
 —
 527
Total Revenues $4,318
 $177
 $—
 $4,495
         
Operating income (loss) (a) $652
 $(750) $(195) $(293)
Depreciation 288
 11
 —
 299
Amortization (b) 149
 —
 7
 156
Unrealized (gains) losses on derivatives and other hedging activities (c) 163
 8
 —
 171
Impairments (d) —
 65
 —
 65
Expenditures for long-lived assets 537
 31
 —
 568

(a)Excludes current and deferred federal and state tax expense (benefit) recorded to Discontinued OperationsIn 2015, the East segment includes impairment charges of $(4)$657 million in 2012, $2 million in 2011 and $(6) million in 2010.  Excludes realized tax expense (benefits) related to stock-based compensation, recorded asgoodwill and other asset impairments. See Notes 14 and 16 for additional information. In 2013, the West segment includes a decrease (increase) to additional paid-in capitalcharge of $(1)$697 million in 2012, $3for the termination of the lease of the Colstrip plant and a $65 million in 2011 and an insignificant amount in 2010.  Excludes tax benefitsimpairment charge related to the issuance costs of the Purchase Contracts, recorded as an increase to additional paid-in capital of an insignificant amount in 2012, $5 million in 2011Corette plant. See Notes 6 and $10 million in 2010, offset by an insignificant amount of related valuation allowances for state deferred taxes in 2012 and 2011.  Also excludes federal, state, and foreign tax expense (benefit) recorded to OCI of $(526) million in 2012, $(137) million in 2011 and $83 million in 2010, and related valuation allowances for state deferred taxes of an insignificant amount in 2012 and $3 million in 2011.

     2012  2011  2010 
Reconciliation of Income Tax Expense         
 Federal income tax on Income from Continuing Operations Before Income Taxes at         
  statutory tax rate - 35% $ 729  $ 770  $ 434 
Increase (decrease) due to:         
 State income taxes, net of federal income tax benefit   27    63    36 
 State valuation allowance adjustments (a)   13    36    (65)
 Impact of lower U.K. income tax rates (b)   (123)   (41)   (20)
 U.S. income tax on foreign earnings - net of foreign tax credit (c)   43    (14)   34 
 Federal and state tax reserves adjustments (d)   (1)   39    (60)
 Foreign tax reserves adjustments (e)   (5)   (141)   
 Federal and state income tax return adjustments (a) (f)   16    (17)   (3)
 Foreign income tax return adjustments   (6)      
 Domestic manufacturing deduction (f) (g)         (11)
 Health Care Reform (h)         8 
 Foreign losses resulting from restructuring (e)         (261)
 Enactment of the U.K.'s Finance Acts (b)   (75)   (69)   (18)
 Federal income tax credits (i)   (12)   (13)   (12)
 Depreciation not normalized (a)   (11)   (20)   (3)
 Foreign valuation allowance adjustments (e)      147    215 
 State deferred tax rate change (j)   (19)   (26)   
 Net operating loss carryforward adjustments (k)   (9)      
 Intercompany interest on U.K. financing entities (l)   (13)   (12)   
 Other   (9)   (11)   (11)
   Total increase (decrease)   (184)   (79)   (171)
Total income taxes from continuing operations $ 545  $ 691  $ 263 
Effective income tax rate  26.2%  31.4%  21.2%

(a)During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes.  The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes.  Due to the decrease in projected taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL recorded $43 million in state deferred income tax expense related to deferred tax valuation allowances during 2011.

Additionally, the 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.  The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012.  The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years.  PPL's tax deduction for 100% bonus regulated tax depreciation was significantly lower in 2012 than in 2011.
268
Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010.  Based on the projected revenue increase related to the expiration of the generation rate caps in 2010, PPL recorded a $72 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances related to the future projections of taxable income over the remaining carryforward period of the net operating losses.
(b)The U.K.'s Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013.  As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2012 related to both rate decreases.

The U.K.'s Finance Act of 2011, enacted in July 2011, reduced the U.K. statutory income tax rate from 27% to 26% retroactive to April 1, 2011 and from 26% to 25% effective April 1, 2012.  As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2011 related to both rate decreases.

The U.K.'s Finance Act of 2010, enacted in July 2010, reduced the U.K. statutory income tax rate from 28% to 27% effective April 1, 2011.  As a result, PPL reduced its net deferred tax liabilities and recognized a deferred tax benefit during 2010.
(c)During 2012, PPL recorded a $23 million adjustment to federal income tax expense related to the recalculation of 2010 U.K. earnings and profits and $19 million of U.S. income tax expense on foreign earnings of certain U.K. financing entities not indefinitely reinvested.

During 2011, PPL recorded a $28 million federal income tax benefit related to U.K. pension contributions.

During 2010, PPL recorded additional U.S. income tax expense primarily resulting from increased taxable dividends.
(d)In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD.  PPL filed its federal income tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable.  In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes.  As a result, and with the finalization of other issues, PPL recorded a $42 million tax benefit in 2010.  In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit).  In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision, holding that the U.K. WPT is not a creditable tax.  As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011.  In February 2012, PPL filed a petition for rehearing of the Third Circuit's opinion.  In March 2012, the Third Circuit denied PPL's petition.  In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company.  In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion.  The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013.  PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.

In July 2010, the Tax Court ruled in PPL's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years.  As a result, PPL recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes.  The IRS did not appeal this decision.

PPL recorded a tax benefit of $6 million during 2012 and 2011 and $7 million during 2010 to federal and state income tax reserves related to stranded cost securitization.
(e)During 2012, PPL recorded a foreign tax benefit following resolution of a U.K. tax issue related to interest expense.

During 2011, WPD reached an agreement with HMRC related to the amount of the capital losses that resulted from prior years' restructuring in the U.K. and recorded a $147 million foreign tax benefit for the reversal of tax reserves related to the capital losses.  Additionally, WPD recorded a $147 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.

During 2010, PPL recorded a $261 million foreign tax benefit in conjunction with losses resulting from restructuring in the U.K.  A portion of these losses offset tax on a deferred gain from a prior year sale of WPD's supply business.  WPD recorded a $215 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.
(f)During 2012, PPL recorded federal and state income tax expense related to the filing of the 2011 federal and state income tax returns.  Of this amount, $5 million relates to the reversal of prior years' state income tax benefits related to regulated depreciation.  PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year.  In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets.  The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes.  PPL adopted the safe harbor method with the filing of its 2011 federal income tax return.

During 2011, PPL recorded federal and state tax benefits related to the filing of the 2010 federal and state income tax returns.  Of this amount, $7 million in tax benefits related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts and $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated state tax depreciation.
(g)In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property.  The increased tax depreciation eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 2011.
(h)Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.  As a result, PPL recorded deferred income tax expense during 2010.  See Note 1314 for additional information.
(i)During 2012, 2011
(b)Represents non-cash items that include the amortization of nuclear fuel, debt discounts and 2010, PPL recorded a deferred tax benefit related to investment tax credits on progress expenditures related to hydroelectric plant expansions.  premiums, debt issuance costs, emission allowances and RECs.
(c)See Note 815 for additional information.
(j)In 2011, PPL completed the sale of certain non-core generation facilities.  
(d)See Note 9 for additional information.  Due to changes in state apportionment resulting in reductions in the future estimated state tax rate, PPL recorded deferred tax benefits related to its December 31, 2012Notes 14 and 2011 state deferred tax liabilities.
(k)During 2012, PPL recorded adjustments to deferred taxes related to net operating loss carryforwards of LKE based on income tax return adjustments.
(l)During 2012 and 2011, PPL recorded foreign income tax benefits related to interest expense on intercompany loans for which there was no domestic income tax expense.

269
    2012  2011  2010 
Taxes, other than income         
 State gross receipts $ 135  $ 140  $ 145 
 State utility realty   2    (9)   5 
 State capital stock   7    18    6 
 Foreign property (a)   147    113    52 
 Domestic property and other (b)   75    64    30 
 Total $ 366  $ 326  $ 238 

(a)
The increase between 2011 and 2010 is due primarily to the acquisition of WPD Midlands on April 1, 2011.  See Note 1016 for additional information.
(b)The increase between 2011 and 2010 is due primarily to the acquisition of LKE on November l, 2010.  See Note 10
(e)Does not include expenditures for additional information.        business acquisitions.
(f)Other primarily consists of unallocated items, including cash and PP&E.


90

3.  Earnings (Loss) Per Share for Talen Energy Corporation

(On June 1, 2015, the spinoff date, Talen Energy Corporation issued 128,499,023 shares of common stock, including 83,524,365 shares issued to PPL's shareholder's and 44,974,658 shares issued in a private placement to the Riverstone Holders. To calculate basic and diluted EPS for periods presented prior to June 1, 2015, Talen Energy Corporation used the shares issued to PPL's shareholders on the date of the spinoff as Talen Energy Corporation was a wholly owned subsidiary of PPL Energy Supply)and no shares were outstanding prior to that date. The calculation of basic and diluted earnings per share for 2015 utilized the weighted-average shares outstanding during the year assuming the shares issued to PPL's shareholders were outstanding during the entire year and reflects the impact of the private placement of shares to the Riverstone Holders on the spinoff date. For 2014 and 2013, weighted average shares outstanding assumed the shares issued to PPL's shareholders at the spinoff date in 2015 were outstanding during those entire years.

DeferredBasic EPS is computed by dividing income taxes reflectby the net tax effectsweighted-average number of temporary differences betweencommon shares outstanding during the carryingapplicable period. Diluted EPS is computed by dividing income by the weighted-average number of common shares outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares as calculated using the Treasury Stock Method.

Reconciliations of the amounts of assetsincome and liabilitiesshares of Talen Energy Corporation common stock (in thousands) for accounting purposes and their basis for income tax purposes and the tax effects of net operating loss and tax credit carryforwards.years ended December 31 used in the EPS calculation are:
  2015 2014 2013
       
Income (Numerator)      
  Attributable to Talen Energy Corporation Stockholders      
Income (Loss) from continuing operations after income taxes $(341) $187
 $(262)
Income (Loss) from discontinued operations (net of income taxes) —
 223
 32
Net Income (Loss) $(341) $410
 $(230)
Shares of Common Stock (Denominator)      
Weighted-average shares - Basic EPS 109,898
 83,524
 83,524
Weighted-average shares - Diluted EPS 109,898
 83,524
 83,524

Net deferred tax assetsShare-based payment awards of 731 thousand were excluded from weighted-average shares in the computation of diluted EPS for 2015 because the effect would have been recognized based on management's estimates of future taxable income for the U.S. jurisdictions in which PPL Energy Supply's operations have historically been profitable.antidilutive.

Significant components of PPL Energy Supply's deferred income tax assets4.  Income and liabilities were as follows:Other Taxes

    2012  2011 
Deferred Tax Assets      
 Deferred investment tax credits $ 75  $ 55 
 Accrued pension costs   94    100 
 Federal loss carryforwards   51    1 
 Federal tax credit carryforwards   113    58 
 State loss carryforwards   79    78 
 Other   68    80 
 Valuation allowances   (74)   (72)
  Total deferred tax assets   406    300 
         
Deferred Tax Liabilities      
 Plant - net   1,579    1,407 
 Unrealized gain on qualifying derivatives   173    380 
 Other   44    51 
  Total deferred tax liabilities   1,796    1,838 
Net deferred tax liability $ 1,390  $ 1,538 

At December 31, PPL Energy Supply had the following loss and tax credit carryforwards.   
        
   2012   Expiration
Loss carryforwards      
 Federal net operating losses $ 143   2031-2032
 Federal charitable contributions   3   2016 
 State net operating losses   1,202   2013-2032
        
Credit carryforwards      
 Federal investment tax credit   108   2031-2032
 Federal - other   5   2031-2032
        

Valuation allowances have been established for the amount that, more likely than not, will not be realized.  The changes in deferred tax valuation allowances were:    

     Additions       
  Balance at    Charged to     Balance
  Beginning Charged Other     at End
  of Period to Income Accounts Deductions of Period
                  
2012  $ 72  $ 2          $ 74 
2011    408    22      $ 358 (a)   72 
2010    255    205        52 (b)   408 

(a)
During 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Funding.  See Note 9 for additional information.
(b)Resulting from the projected revenue increase in connection with the expiration of the Pennsylvania generation rate caps in 2010, the valuation allowance related to state net operating loss carryforwards over the remaining carryforward period was reduced by $52 million.        
270
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income (Loss) from Continuing Operations Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:

     2012  2011  2010 
Income Tax Expense (Benefit)         
 Current - Federal $ 89  $ 139  $ 208 
 Current - State   22    (12)   78 
   Total Current Expense (Benefit)   111    127    286 
 Deferred - Federal   193    251    66 
 Deferred - State   10    70    (89)
   Total Deferred Expense (Benefit), excluding operating loss carryforwards   203    321    (23)
             
 Investment tax credit, net - federal   (2)   (3)   (2)
 Tax benefit of operating loss carryforwards         
  Deferred - Federal   (48)      
  Deferred - State   (1)      
   Total Tax Benefit of Operating Loss Carryforwards   (49)      
 Total income taxes from continuing operations (a) $ 263  $ 445  $ 261 
             
 Total income tax expense - Federal $ 232  $ 387  $ 272 
 Total income tax expense (benefit) - State   31    58    (11)
   Total income taxes from continuing operations (a) $ 263  $ 445  $ 261 

(a)
Excludes current and deferred federal, state and foreign tax expense (benefit) recorded to Discontinued Operations of $3 million in 2011 and $(5) million in 2010.  Also, excludes federal, state and foreign tax expense (benefit) recorded to OCI of $(267) million in 2012, $(83) million in 2011 and $132 million in 2010.  The deferred tax benefit of operating loss carryforwards was insignificant for 2011 and 2010.        

     2012  2011  2010 
Reconciliation of Income Tax Expense         
 Federal income tax on Income from Continuing Operations Before Income Taxes at         
  statutory tax rate - 35% $ 258  $ 424  $ 308 
Increase (decrease) due to:         
 State income taxes, net of federal income tax benefit   33    60    41 
 State valuation allowance adjustments (a)   2    22    (52)
 State deferred tax rate change (b)   (19)   (26)   
 Federal and state tax reserves adjustments   (2)   2    (11)
 Domestic manufacturing deduction (c) (d)         (11)
 Federal and state income tax return adjustments (d)   4    (22)   (6)
 Health Care Reform (e)         5 
 Federal income tax credits (f)   (12)   (12)   (12)
 Other   (1)   (3)   (1)
   Total increase (decrease)   5    21    (47)
Total income taxes from continuing operations $ 263  $ 445  $ 261 
Effective income tax rate  35.6%  36.7%  29.6%

(a)
During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes.  The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for Federal income tax purposes.  Due to the decrease in projected taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL Energy Supply recorded $22 million in state deferred income tax expense related to deferred tax valuation allowances during 2011.

Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010.  Based on the projected revenue increase related to the expiration of the generation rate caps, PPL Energy Supply recorded a $52 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances over the remaining carry forward period of the net operating losses during 2010.
(b)In 2011, PPL Energy Supply completed the sale of certain non-core generation facilities.  See Note 9 for additional information.  Due to changes in state apportionment resulting in reductions in the future estimated state tax rate, PPL Energy Supply recorded deferred tax benefits related to its December 31, 2012 and 2011 state deferred tax liabilities.
(c)In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property.  The increased tax depreciation deduction eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 2011.
(d)During 2011, PPL recorded federal and state tax benefits related to the filing of the 2010 federal and state income tax returns.  Of this amount, $7 million in tax benefits related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts.
(e)Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.  As a result, PPL Energy Supply recorded deferred income tax expense during 2010.  See Note 13 for additional information.
(f)During 2012, 2011 and 2010, PPL Energy Supply recorded a deferred tax benefit related to investment tax credits on progress expenditures related to hydroelectric plant expansions.  See Note 8 for additional information.                    
271
    2012  2011  2010 
Taxes, other than income         
 State gross receipts $ 35  $ 31  $ 15 
 State capital stock   5    12    4 
 Property and other   29    28    27 
  Total $ 69  $ 71  $ 46 

(PPL Electric)

The provision for PPL Electric's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the PUC and the FERC.  The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulated liabilities" on the Balance Sheets.

Significant components of PPL Electric's deferred income tax assets and liabilities were as follows:

    2012  2011 
Deferred Tax Assets      
 Accrued pension costs $81  $93 
 Contributions in aid of construction  106   104 
 Regulatory obligations  24   28 
 State loss carryforwards  39   26 
 Federal loss carryforwards  81   3 
 Other  46   29 
  Total deferred tax assets  377   283 
         
Deferred Tax Liabilities      
 Electric utility plant - net  1,229   1,078 
 Taxes recoverable through future rates  122   120 
 Reacquired debt costs  27   32 
 Other regulatory assets  174   127 
 Other  12   16 
  Total deferred tax liabilities  1,564   1,373 
Net deferred tax liability $1,187  $1,090 

At December 31, PPL Electric had the following loss carryforwards.   
        
   2012   Expiration
        
Loss carryforwards      
 Federal net operating losses $ 229   2031-2032
 Federal charitable contributions   2   2016
 State net operating losses   597   2030-2032

Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:   
     2012  2011  2010 
Income Tax Expense (Benefit)         
 Current - Federal $ (28) $ (25) $ (127)
 Current - State   (18)   (13)   (14)
   Total Current Expense (Benefit)   (46)   (38)   (141)
 Deferred - Federal   162    123    184 
 Deferred - State   42    25    27 
   Total Deferred Expense (Benefit), excluding operating loss carryforwards   204    148    211 
             
 Investment tax credit, net - Federal   (1)   (2)   (2)
 Tax benefit of operating loss carryforwards         
  Deferred - Federal   (72)   (12)   6 
  Deferred - State   (17)   (28)   (17)
   Total Tax Benefit of Operating Loss Carryforwards   (89)   (40)   (11)
 Total income tax expense $ 68  $ 68  $ 57 
             
 Total income tax expense - Federal $ 61  $ 84  $ 61 
 Total income tax expense (benefit) - State   7    (16)   (4)
   Total income tax expense $ 68  $ 68  $ 57 
272
     2012  2011  2010 
Reconciliation of Income Taxes         
 Federal income tax on Income Before Income Taxes at statutory tax rate - 35% $ 71  $ 90  $ 67 
Increase (decrease) due to:         
 State income taxes, net of federal income tax benefit   9    12    9 
 Amortization of investment tax credit   (1)   (2)   (2)
 Federal and state tax reserves adjustments (a)   (8)   (9)   (12)
 Federal and state income tax return adjustments (b) (c)   7    (4)   (1)
 Depreciation not normalized (c)   (8)   (17)   (3)
 Other   (2)   (2)   (1)
   Total increase (decrease)   (3)   (22)   (10)
Total income tax expense $ 68  $ 68  $ 57 
Effective income tax rate  33.3%  26.5%  29.7%
(a)In July 2010, the U.S. Tax Court ruled in PPL Electric's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years.  As a result, PPL Electric recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes.  The IRS did not appeal this decision.

PPL Electric recorded a tax benefit of $6 million during 2012 and 2011 and $7 million during 2010 to federal and state income tax reserves related to stranded cost securitization.
(b)PPL Electric changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year.  In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets.  The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes.  PPL Electric adopted the safe harbor method with the filing of its 2011 federal income tax return and recorded a $5 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation.

During 2011, PPL Electric recorded a $5 million federal and state income tax benefit as a result of filing its 2010 federal and state income tax returns.  Of this amount, $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated 100% bonus tax depreciation.
(c)During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes.  The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes.  The 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation.  The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012.  The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years.  PPL Electric's tax deduction for 100% bonus depreciation was significantly lower in 2012 than in 2011.

    2012  2011  2010 
Taxes, other than income         
 State gross receipts $ 101  $ 109  $ 130 
 State utility realty (a)   2    (10)   5 
 State capital stock   1    4    2 
 Property and other   1    1    1 
  Total $ 105  $ 104  $ 138 

(a)2011 includes PURTA tax that was refunded to PPL Electric customers in 2011.

(LKE)

The provision for LKE's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC, VSCC, TRA and the FERC.  The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.

Significant components of LKE's deferred income tax assets and liabilities were as follows:

    2012  2011 
Deferred Tax Assets      
 Net operating loss carryforward $376  $318 
 Federal tax credit carryforwards  170   170 
 Regulatory liabilities  99   124 
 Accrued pension costs  42   67 
 State capital loss carryforward  5   5 
 Income taxes due to customers  26   30 
 Deferred investment tax credits  54   56 
 Other  41   30 
 Valuation allowances  (5)  (5)
  Total deferred tax assets  808   795 
273
    2012  2011 
Deferred Tax Liabilities      
 Plant - net  1,171   986 
 Regulatory assets  152   180 
 Other  13   25 
  Total deferred tax liabilities  1,336   1,191 
Net deferred tax liability $528  $396 
 2015 2014 2013
Income Tax Expense (Benefit)     
Current - Federal$43
 $28
 $118
Current - State—
 13
 16
Total Current Expense43
 41
 134
Deferred - Federal(22) 66
 (263)
Deferred - State(37) 11
 (27)
Total Deferred Expense (Benefit)(59) 77
 (290)
Investment tax credit, net - federal(11) (2) (3)
Total income taxes (benefits) from continuing operations (a)$(27) $116
 $(159)
Total income tax expense (benefit) - Federal$10
 $92
 $(148)
Total income tax expense (benefit) - State(37) 24
 (11)
Total income taxes (benefits) from continuing operations (a)$(27) $116
 $(159)

LKE expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.

At December 31, LKE had the following loss and tax credit carryforwards.

   2012  Expiration
       
Loss carryforwards     
 Federal net operating losses $ 948  2028-2032
 State net operating losses   1,173  2028-2032
 State capital losses   119  2013-2016
       
Credit carryforwards     
 Federal investment tax credit��  125  2025-2028
 Federal alternative minimum tax credit   20  Indefinite
 Federal - other   25  2016-2032
 State - other  4  2022 

Changes in deferred tax valuation allowances were:

  Balance at        Balance
  Beginning      at End
  of Period Additions Deductions of Period
              
2012  $ 5         $ 5 
2011    6     $ 1 (a)   5 
2010    7  $ 6 (b)  7 (c)   6 
(a)Primarily related to the expiration of state capital loss carryforwards.
(b)A valuation allowance was recorded against deferred tax assets for state capital loss carryforwards.
(c)Related to release of a valuation allowance associated with federal capital loss carryforwards due to the LKE acquisition by PPL.
Details of the components of income tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income (Loss) from Continuing Operations Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:

    Successor  Predecessor
         Two Months  Ten Months
    Year Ended Year Ended Ended  Ended
    December 31, December 31, December 31,  October 31,
    2012  2011  2010   2010 
Income Tax Expense (Benefit)            
 Current - Federal$ (32) $ (71) $ (31)  $33 
 Current - State  2    6   4    11 
   Total Current Expense (Benefit)  (30)   (65)   (27)    44 
 Deferred - Federal  185    208    52     62 
 Deferred - State  15    16    1     5 
   Total Deferred Expense, excluding operating loss carryforwards  200    224    53     67 
 Investment tax credit, net - Federal  (6)   (6)   (1)    (2)
 Tax benefit of operating loss carryforwards            
  Deferred - Federal  (46)          
  Deferred - State  (12)          
   Total Tax Benefit of Operating Loss Carryforwards  (58)          
 Total income tax expense from continuing operations (a)$ 106  $ 153  $ 25   $ 109 
                
 Total income tax expense - Federal$ 101  $ 131  $ 20   $ 93 
 Total income tax expense - State  5    22    5     16 
   Total income tax expense from continuing operations (a)$ 106  $ 153  $ 25   $ 109 

(a)Excludes current and deferred federal and state tax expense (benefit) recorded to Discontinued Operations of $(4)$109 million and $17 million in 2012, $(1) million in 2011, $1 million for the two month period ended December 31, 20102014 and $(1) million for the ten month period ended October 31, 2010.2013. Also excludes deferred federal and state tax expense (benefit) recorded to OCI of $(12)$(1) million, $(56) million and $47 million in 2012, $(1) million2015, 2014 and 2013.


91

 2015 2014 2013
Reconciliation of Income Tax Expense     
Federal income tax on Income from Continuing Operations Before Income Taxes at statutory tax rate - 35%$(129) $106
 $(147)
Increase (decrease) due to:     
State income taxes, net of federal income tax benefit(3) 17
 (24)
Federal and state tax reserve adjustments (a)(12) —
 —
Federal income tax credits (b)(9) —
 (8)
State deferred tax rate change, net of federal benefit (c)(17) (1) 15
Federal and state income tax return adjustments(7) —
 —
Goodwill Impairment (d)144
 —
 —
Other6
 (6) 5
Total increase (decrease)102
 10
 (12)
Total income taxes$(27) $116
 $(159)
Effective income tax rate7.4% 38.3% 37.9%

(a)In 2015, open audits for the tax years 2008-2011 were settled by PPL with the IRS resulting in 2011, $3a tax benefit of $12 million for Talen Energy's portion of the two month period endedsettlement of previously unrecognized tax benefits.
(b)
During 2015, Talen Energy recorded a benefit primarily related to the recognition of previously unamortized tax credits as a result of the sale of Talen Renewable Energy in November 2015. During 2013, Talen Energy recorded deferred tax benefits related to investment tax credits on progress expenditures for the Holtwood hydroelectric plant expansion. See Note 6 for additional information.
(c)
During 2015, 2014 and 2013, Talen Energy recorded adjustments related to its December 31 2010state deferred tax liabilities as a result of annual changes in state apportionment and $(7) millionthe impact on the future estimated state income tax rate.
(d)A significant portion of the impairment was related to non-deductible goodwill. See Note 16 for additional information on the ten month period ended October 31, 2010.goodwill impairment.
274
     Successor  Predecessor
           Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Reconciliation of Income Taxes             
 Federal income tax on Income Before Income Taxes at             
  statutory tax rate - 35% $ 116  $ 147  $ 25   $ 105 
Increase (decrease) due to:             
 State income taxes, net of federal income tax benefit   6    15    2     9 
 Amortization of investment tax credit   (6)   (5)       (2)
 Net operating loss carryforward (a)   (9)          
 Other   (1)   (4)   (2)    (3)
   Total increase (decrease)   (10)   6        4 
Total income tax expense from continuing operations $ 106  $ 153  $ 25   $ 109 
Effective income tax rate  32.0%  36.5%  35.7%   36.3%
 2015 2014 2013
Taxes, other than income     
State gross receipts$41
 $45
 $37
State capital stock1
 1
 1
Property and other23
 11
 15
Total$65
 $57
 $53

(a)During 2012, LKE recorded adjustments to deferred taxes related to net operating loss carryforwards based on income tax return adjustments.

     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Taxes, other than income             
 Property and other $ 46  $ 37  $ 2   $ 21 
   Total $ 46  $ 37  $ 2   $ 21 

(LG&E)

The provision for LG&E's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC and the FERC.  The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.

SignificantAt December 31, significant components of LG&E'sTalen Energy's deferred income tax assets and liabilities were as follows:follows
 2015 2014
Deferred Tax Assets   
Deferred investment tax credits$6
 $11
Accrued pension costs121
 98
Federal net operating loss carryforwards110
 22
Federal tax credit carryforwards—
 13
State net operating loss carryforwards19
 79
Other105
 79
Valuation allowances(10) (78)
Total deferred tax assets351
 224
 

 

Deferred Tax Liabilities   
Plant - net1,874
 1,374
Unrealized gain on qualifying derivatives53
 28
Other10
 42
Total deferred tax liabilities1,937
 1,444
Net deferred tax liability$1,586
 $1,220

92

    2012  2011 
Deferred Tax Assets      
 Regulatory liabilities $54  $65 
 Deferred investment tax credits  16   17 
 Income taxes due to customers  21   23 
 Other  9   10 
  Total deferred tax assets  100   115 
         
Deferred Tax Liabilities      
 Plant - net  526   462 
 Regulatory assets  86   98 
 Accrued pension costs  27   19 
 Other  9   9 
  Total deferred tax liabilities  648   588 
Net deferred tax liability $548  $473 
Table of Contents


LG&E expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.

At December 31, 2012, LG&ETalen Energy had $22 million ofthe following federal and state net operating loss carryforwards.
 2015 Expiration
Loss carryforwards   
Federal net operating losses (a) (b)$314
 2028-2034
State net operating losses (a) (b)274
 2016-2035

(a) The federal and state net operating loss carryforwards that expire in 2030.
Detailspresented above are net of the components of incomeunrecognized tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxesbenefits recorded for reporting purposes, and details of "Taxes, other than income" were:     
275
     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Income Tax Expense (Benefit)             
 Current - Federal $ (2) $ 12  $ (4)  $32 
 Current - State   3    8   1    5 
   Total Current Expense (Benefit)   1    20    (3)    37 
 Deferred - Federal   65    52    12     21 
 Deferred - State   6    2    1     2 
   Total Deferred Expense   71    54    13     23 
 Investment tax credit, net - Federal   (3)   (3)       (2)
   Total income tax expense (a) $ 69  $ 71  $ 10   $ 58 
                 
 Total income tax expense - Federal $ 60  $ 61  $ 8   $ 51 
 Total income tax expense - State   9    10    2     7 
   Total income tax expense (a) $ 69  $ 71  $ 10   $ 58 

(a)Excludes deferred federal and state tax expense recorded to OCI of $7 million for the ten month period ended October 31, 2010.

     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Reconciliation of Income Taxes             
 Federal income tax on Income Before Income Taxes at             
  statutory tax rate - 35% $ 67  $ 68  $ 10   $ 58 
Increase (decrease) due to:             
 State income taxes, net of federal income tax benefit   5    7    1     4 
 Other   (3)   (4)   (1)    (4)
   Total increase (decrease)   2    3        
Total income tax expense $ 69  $ 71  $ 10   $ 58 
Effective income tax rate  35.9%  36.4%  34.5%   34.7%

     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Taxes, other than income             
 Property and other $ 23  $ 18  $ 1   $ 12 
   Total $ 23  $ 18  $ 1   $ 12 

(KU)

The provision for KU's deferred income taxes for regulated assets and liabilities is based upon the ratemaking principles reflected in rates established by the KPSC, VSCC, TRA and the FERC.  The difference in the provision for deferred income taxes for regulated assets and liabilities and the amount that otherwise would be recorded under GAAP is deferred and included in "Regulatory assets" or "Regulatory liabilities" on the Balance Sheets.

Significant components of KU's deferred income tax assets and liabilities were as follows:

    2012  2011 
Deferred Tax Assets      
 Regulatory liabilities $45  $58 
 Deferred investment tax credits  38   39 
 Net operating loss carryforward  20    
 Income taxes due to customers  5   7 
 Accrued pension costs  (5)  9 
 Other  7   6 
  Total deferred tax assets  110   119 
276
    2012  2011 
Deferred Tax Liabilities      
 Plant - net  623   500 
 Regulatory assets  65   82 
 Other  5   16 
  Total deferred tax liabilities  693   598 
Net deferred tax liability $583  $479 

KU expects to have adequate levels of taxable income to realize its recorded deferred income tax assets.

At December 31, 2012, KU had $56 million(b) A portion of federalthe net operating loss carryforwards that expireconsist of tax losses obtained as a result of the acquisition of MACH Gen. The utilization of these carryforwards are subject to annual limitations imposed by Section 382 of the Internal Revenue Code, which limits a company’s ability to deduct prior net operating losses following a more than 50 percent change in 2032.ownership. The Section 382 limitation is not expected to prevent Talen Energy from utilizing its federal loss carryforwards in future years. State net operating loss carryforwards are also dependent upon state taxable income or loss, the state’s proportion of taxable net income and the application of state laws, which can change from year to year and impact the amount of such carryforward utilization.

Details ofValuation allowances have been established for the components of incomeamount that, more likely than not, will not be realized. The changes in deferred tax expense, a reconciliation of federal income taxes derived from statutory tax rates applied to "Income Before Income Taxes" to income taxes for reporting purposes, and details of "Taxes, other than income" were:    valuation allowances were as follows:
   Additions    
 Balance at Beginning of Period Charged to Income Charged to Other Accounts (a) Reductions Balance at End of Period
2015$78
 $—
 $(68) $—
 $10
201478
 —
 —
 —
 78
201374
 4
 —
 —
 78

    Successor  Predecessor
         Two Months  Ten Months
    Year Ended Year Ended Ended  Ended
    December 31, December 31, December 31,  October 31,
    2012  2011  2010   2010 
Income Tax Expense (Benefit)            
 Current - Federal$ (20) $ (8) $13   $46 
 Current - State  (1)   4   3    9 
   Total Current Expense (Benefit)  (21)   (4)   16     55 
 Deferred - Federal  111    101    4     20 
 Deferred - State  11    10        3 
   Total Deferred Expense, excluding operating loss carryforwards  122    111    4     23 
 Investment tax credit, net - Federal  (3)   (3)       
 Tax benefit of operating loss carryforwards            
  Deferred - Federal  (20)          
   Total Tax Benefit of Operating Loss Carryforwards  (20)          
 Total income tax expense (a)$ 78  $ 104  $ 20   $ 78 
                
 Total income tax expense - Federal$ 68  $ 90  $ 17   $ 66 
 Total income tax expense - State  10    14    3     12 
   Total income tax expense (a)$ 78  $ 104  $ 20   $ 78 

(a)Excludes deferred federal and state tax (benefit) recorded to OCI of $1 million in 2012 and $(1)2015 decreased by $78 million for valuation allowances against deferred tax assets retained by PPL upon spinoff and increased by $10 million for valuation allowances established against deferred tax assets acquired in the ten month period ended October 31, 2010.MACH Gen acquisition in November 2015.

     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Reconciliation of Income Taxes             
 Federal income tax on Income Before Income Taxes at             
  statutory tax rate - 35% $ 75  $ 99  $ 19   $ 77 
Increase (decrease) due to:             
 State income taxes, net of federal income tax benefit   6    9    2     8 
 Other   (3)   (4)   (1)    (7)
   Total increase (decrease)   3    5    1     1 
Total income tax expense $ 78  $ 104  $ 20   $ 78 
Effective income tax rate  36.3%  36.9%  36.4%   35.8%

     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
Taxes, other than income             
 Property and other $ 23  $ 19  $ 1   $ 9 
   Total $ 23  $ 19  $ 1   $ 9 
277
Unrecognized Tax Benefits(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Changes to unrecognized tax benefits were as follows:

   2012  2011 
PPL      
 Beginning of period $145  $251 
 Additions based on tax positions of prior years  15   40 
 Reductions based on tax positions of prior years  (61)  (160)
 Additions based on tax positions related to the current year  7   25 
 Reductions based on tax positions related to the current year  (3)  (4)
 Settlements  (2)   
 Lapse of applicable statute of limitation  (9)  (10)
 Effects of foreign currency translation     3 
 End of period $92  $145 
        
PPL Energy Supply      
 Beginning of period $28  $183 
 Additions based on tax positions of prior years  4   1 
 Reductions based on tax positions of prior years  (2)   
 Reductions based on tax positions related to the current year     (1)
 Derecognize unrecognized tax benefits (a)     (155)
 End of period $30  $28 
        
PPL Electric      
 Beginning of period $73  $62 
 Reductions based on tax positions of prior years  (43)   
 Additions based on tax positions related to the current year  5   22 
 Reductions based on tax positions related to the current year     (1)
 Lapse of applicable statute of limitation  (9)  (10)
 End of period $26  $73 
 2015 2014
Beginning of period$15
 $15
Increases based on tax positions of prior years (a)31
 —
Decreases relating to settlements with taxing authorities (b)(15) —
End of period$31
 $15

(a)RepresentsIncreased unrecognized tax benefits derecognizedwere established to offset the deferred tax asset related to net operating loss carryforwards as a result of PPL Energy Supply's distributionthe MACH Gen acquisition in November 2015.
(b)Decreased as a result of its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.  See Note 9IRS audit settlements for additional information ontax years 1998-2011 during the distribution.year ended December 31, 2015.

LKE's, LG&E's and KU's unrecognized tax benefits and changes in those unrecognized tax benefits are insignificant at December 31, 2012 and December 31, 2011.

At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase or decrease by the following amounts.  For LKE, LG&E and KU, no significant changesA change in unrecognized tax benefits are projected overis not expected to occur in the next 12twelve months.

  Increase Decrease
       
PPL $10  $90 
PPL Energy Supply  1   30 
PPL Electric  11   25 

These potential changes could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the creditability of foreign taxes, the timing and utilization of foreign tax credits and the related impact on alternative minimum tax and other credits, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups.  The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.

At December 31, 2015 and 2014 the total unrecognized tax benefits and related indirect effects that, if recognized, would decreaseimpact the effective tax rate were as follows.  The amounts for LKE, LG&E$30 million and KU were insignificant.$14 million.

  2012  2011 
       
PPL $38  $41 
PPL Energy Supply  13   13 
PPL Electric  3   8 
278
At December 31, the following2014 a receivable (payable) balances werebalance of $16 million was recorded for interest related to tax positions.  The amounts for LKE, LG&E and KU were insignificant.

  2012  2011 
       
PPL $(16) $(20)
PPL Energy Supply  17   2 
PPL Electric  1   8 
positions, which was settled in connection with the 1998-2011 IRS settlement, prior to the spinoff from PPL.

The following interest expense (benefit) was recognized in income taxes.  The amountstaxes for LKE, LG&E and KU were insignificant.the years ended December 31.
 2015 2014 2013
 $—
 $(1) $5


  2012  2011  2010 
          
PPL $ (4) $ 27  $ (39)
PPL Energy Supply   (4)   6    (30)
PPL Electric   (4)   (5)   (8)
93

PPL or its subsidiaries file tax returns in five major tax jurisdictions.  Table of Contents

The federal and state income tax provisions for PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU are calculated in accordance with an intercompany tax sharing agreement which provides that taxable income be calculated as if each domestic subsidiary filed a separate consolidated return. Based on this tax sharing agreement, PPLTalen Energy Supply or its subsidiaries indirectly or directly file tax returns in three major tax jurisdictions, PPL Electric or its subsidiaries indirectly or directly file tax returnsprimarily in two major tax jurisdictions, and LKE, LG&E and KU or their subsidiaries indirectly or directly file tax returns in two major tax jurisdictions. With few exceptions, at December 31, 2012, these jurisdictions, as well as2015, the tax years in these jurisdictions that are no longerremain subject to examination were as follows:  are:

PPL
PPLEnergy SupplyPPL ElectricLKELG&EKU
U.S. (federal) (a)1997 and prior1997 and prior1997 and prior10/31/2010 and prior10/31/2010 and prior10/31/2010 and prior2009 - present
Pennsylvania (state)2012 - present

5.  Financing Activities

Credit Arrangements and Short-term Debt

Talen Energy maintains credit arrangements to enhance liquidity and provide credit support. For reporting purposes, on a consolidated basis, the credit arrangements of Talen Energy Supply and its subsidiaries also apply to Talen Energy Corporation.
Revolving Credit Facilities

The following secured revolving credit facilities were in place at December 31, 2015:         
 
Expiration
Date
 Capacity Borrowed (c) Letters of
Credit
Issued		 
Unused
Capacity
 
Talen Energy Supply RCF (a)June 2020 $1,850
 $500
 $163
 $1,187
 
New MACH Gen RCF (b)July 2021 160
 108
 31
 21
 
      Total Credit Facilities  $2,010
 $608
 $194
 $1,208
 

2008 and prior2008 and prior2008 and prior
Kentucky (state)(a)The facility is syndicated and provides capacity available for short-term borrowings and up to $925 million of letters of credit. The facility requires Talen Energy Supply to maintain a senior secured net debt to adjusted EBITDA ratio (as defined in the agreement) of less than or equal to 4.50 to 1.00 as of the last day of any fiscal quarter. Talen Energy Supply pays customary fees on the facility and borrowings bear interest at its option at either a defined base rate or LIBOR-based rates, in each case plus an applicable margin. The weighted average interest rate on outstanding borrowings at December 31, 2015 was 2.67%.
2008 and prior2010 and prior2010 and prior2010 and prior
Montana (state)(b)
The facility provides capacity available for short-term borrowings and up to $120 million of letters of credit. New MACH Gen pays customary fees on the facility and borrowings bear interest at 12-month LIBOR, plus an applicable margin. The weighted average interest rate on outstanding borrowings at December 31, 2015 was 5.04%.
2008 and prior2008 and prior
U.K. (foreign)(c)The amounts borrowed are recorded as "Short-term debt" on the Balance Sheet.

The Talen Energy Supply RCF was entered into on June 1, 2015 in connection with the completion of the spinoff transaction and replaced Talen Energy Supply's previously existing unsecured syndicated credit facility. Any outstanding principal amounts under the old facility were repaid prior to the termination of the old facility and outstanding letters of credit were transferred to the Talen Energy Supply RCF. The facility is secured by liens on a majority of Talen Energy Supply's assets and is guaranteed by certain Talen Energy Supply subsidiaries, which guarantees are in turn secured by liens on assets of such subsidiaries with an aggregate carrying value of $7 billion at December 31, 2015. The facility provides the option to raise incremental credit facilities, refinance the loans with debt incurred outside the facility and extend the maturity date of the revolving credit commitments and loans and, if applicable, term loans, subject to certain limitations.

The Talen Energy Supply letter of credit facility and uncommitted credit facilities that existed at December 31, 2014 either expired or matured during the first quarter of 2015. Any previously issued letters of credit under these facilities were either terminated or reissued under the then-outstanding unsecured syndicated credit facility and upon closing of the spinoff were reissued under the Talen Energy Supply RCF described above. During the year ended December 31, 2015, Talen Energy wrote-off $12 million of unamortized fees to "Interest expense" on the Statements of Income as a result of the termination of the prior unsecured syndicated credit facility.

The New MACH Gen RCF is a component of the $642 million First Lien Credit and Guaranty Agreement, which was outstanding when Talen Energy acquired MACH Gen in November 2015. The First Lien Credit and Guaranty Agreement also contains a Term Loan B as described in "Long-term Debt" below. Obligations under the First Lien Credit and Guaranty Agreement are guaranteed by each of New MACH Gen's subsidiaries and are secured by a first priority security interest, subject to possible shared first lien status with certain permitted hedge and power sale agreements, in all of the assets of New MACH Gen and each guarantor, including the equity interests in New MACH Gen and each guarantor, which assets collectively have an aggregate carrying value of approximately $1 billion at December 31, 2015. Talen Energy is not a guarantor or obligor of borrowings under the First Lien Credit and Guaranty Agreement.

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Other Facilities

Talen Energy Supply maintains a $500 million agreement expiring June 2017 that provides Talen Energy Supply the ability to request up to $500 million of committed unsecured letter of credit capacity at fees to be agreed upon at the time of each request, based on certain market conditions.  At December 31, 2015, Talen Energy Supply had not requested any capacity for the issuance of letters of credit under this arrangement.

In December 2015, Talen Energy Supply and Talen Energy Marketing entered into the Amended Secured Energy Marketing and Trading Facility Agreement (Amended STF Agreement) to amend the $800 million Secured Energy Marketing and Trading Facility Common Agreement, dated as of November 1, 2010. The Amended STF Agreement increased the facility capacity to $1.3 billion. The facility allows Talen Energy Supply to receive credit to satisfy collateral posting obligations related to Talen Energy's energy marketing and trading activities with counterparties participating in the facility. Prior to the Talen Energy spinoff transactions, Montour, LLC and Brunner Island, LLC had guaranteed certain of Talen Energy Marketing's obligations and had granted mortgage liens on their respective generating facilities to secure such guarantees. Brunner Island and Montour have since been released as parties. Obligations under the Amended STF Agreement are secured by the same collateral that secures the Talen Energy Supply RCF described above. The facility is for a five-year term that is subject to an automatic one-year extension each year until termination under the provisions of the Amended STF Agreement. The initial term expires in December 2020. There were $54 million of secured obligations outstanding under this facility at December 31, 2015.

Long-term Debt

The following long-term debt was outstanding at December 31:
 2015 2014
 Weighted-Average Rate Maturities    
Senior Unsecured Notes5.41% 2016-2038 $3,713
 $2,193
Senior Secured Notes8.86% 2025 41
 45
Term Loan B6.21% 2022 474
 —
Total Long-term Debt Before Adjustments    4,228
 2,238
        
Fair market value adjustments    (23) (19)
Unamortized premium and (discount), net    (2) (1)
Total Long-term Debt    4,203
 2,218
Less current portion of Long-term Debt, including fair market value adjustment    399
 535
Total Long-term Debt, noncurrent    $3,804
 $1,683

The aggregate maturities of long-term debt are as follows:

2016 2017 2018 2019 2020 Thereafter Total
$396
 $5
 $424
 $1,244
 $179
 $1,980
 $4,228

Long-term Debt Activity

In May 2015, Talen Energy Supply issued $600 million of 6.50% Senior Unsecured Notes due 2025. Talen Energy Supply received proceeds of $591 million, net of underwriting fees, which were used for repayment of short-term debt. The notes may be redeemed at Talen Energy Supply's option, in whole at any time or in part from time to time, prior to June 1, 2020 at a price equal to 100% of their principal amount plus a make-whole premium and on or after June 1, 2020 at specified redemption prices. In addition, on or prior to June 1, 2018, up to 35% of the notes may be redeemed by Talen Energy Supply with proceeds from certain equity offerings at a price equal to 106.5% of the principal amount.

In June 2015, Talen Energy Supply assumed $1.25 billion of RJS Power Holdings LLC's 5.125% Senior Notes due 2019 as a result of the merger of RJS Power Holdings LLC into Talen Energy Supply, by which Talen Energy Supply became the obligor of these notes. In connection with this event and pursuant to the terms of the indenture governing the notes, the coupon on the notes was reduced to 4.625% in July 2015.


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In September 2015, Talen Energy Supply completed a remarketing of $231 million of Exempt Facilities Revenue Refunding Bonds, Series 2009A due 2038, Series 2009B due 2038, and Series 2009C due 2037 that were issued by PEDFA on behalf of Talen Energy Supply in 2009. All series bore interest at a fixed rate of 3.0% prior to the remarketing. The Series 2009A Bonds, with a principal amount of $100 million, were remarketed at a fixed coupon of 6.40% to maturity. The Series 2009B Bonds and Series 2009C Bonds, with an aggregate principal amount of $131 million, were remarketed at a fixed rate of 5.00% for five years, at which time they will be subject to mandatory repurchase and optional remarketing. This transaction is excluded from the Statement of Cash Flows as a non-cash transaction.

In October 2015, Talen Energy Supply's $300 million of 5.70% REset Put Securities due 2035 (REPS) were subject to mandatory tender to the remarketing dealer. However, the remarketing dealer and Talen Energy Supply mutually agreed to terminate the remarketing dealer's right to remarket the REPS and, in accordance with the terms of the REPS, Talen Energy Supply repurchased the REPS at par. The total aggregate consideration paid to repurchase the REPS was $434 million, which included $300 million of principal and $134 million of remarketing option value paid to the remarketing dealer. The termination payment to the remarketing dealer was recorded to "Other Income (Expense) - net" on the 2015 Statement of Income and is reflected in "Cash from operating activities" on the 2015 Statement of Cash Flows.

Following the MACH Gen acquisition in November 2015, $475 million of New MACH Gen Term Loan B debt secured under the First Lien Credit and Guaranty Agreement, which is described above, remained outstanding. The Term Loan B provides customary annual amortization paid quarterly and may also be repaid, in whole or in part, beginning in the third quarter of 2016 without any make-whole premium. See "Credit Arrangements and Short-term Debt - Revolving Credit Facilities" above for information regarding guarantees of and security interests with respect to the First Lien Credit and Guaranty Agreement.

In December 2015, Talen Energy Supply announced an "exchange offer" for its 6.5% Senior Unsecured Notes due 2025 that were issued in May 2015. Pursuant to the terms of the notes, Talen Energy Supply offered to exchange all of the outstanding notes for a like principal amount of its 6.5% Senior Notes due 2025 that, have been registered under the Securities Exchange Act of 1933, as amended. In January 2016, the exchange offer was completed with all of the notes exchanged.

In connection with the sale of Talen Ironwood Holdings, LLC, in January 2016, a Talen Ironwood Holdings, LLC subsidiary completed the redemption of $41 million of its 8.857% Senior Secured Notes due 2025 prior to the closing of the sale transaction, which occurred in February 2016. The redemption included the payment of a make whole premium of $14 million, which will be recorded as a component of the expected gain on sale in "Operating Income" on the Statement of Income in 2016. See Note 6 for additional information on the sale of Talen Ironwood Holdings, LLC.

Preferred Stock of Talen Energy Corporation

Talen Energy Corporation is authorized under its Amended and Restated Certificate of Incorporation to issue up to 100 million shares of preferred stock. No shares of preferred stock were issued or outstanding at December 31, 2015.

Legal Separateness

The subsidiaries of Talen Energy Corporation are separate legal entities. Talen Energy Corporation's subsidiaries are not liable for the debts of Talen Energy Corporation. Accordingly, creditors of Talen Energy Corporation may not satisfy their debts from the assets of Talen Energy Corporation's subsidiaries absent a specific contractual undertaking by a subsidiary to pay Talen Energy Corporation's creditors or as required by applicable law or regulation. Similarly, Talen Energy Corporation is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of Talen Energy Corporation's subsidiaries may not satisfy their debts from the assets of Talen Energy Corporation or its other subsidiaries absent a specific contractual undertaking by Talen Energy Corporation or its other subsidiaries to pay the creditors or as required by applicable law or regulation.

Similarly, the subsidiaries of Talen Energy Supply are each separate legal entities. These subsidiaries are not liable for the debts of Talen Energy Supply. Accordingly, creditors of Talen Energy Supply may not satisfy their debts from the assets of their subsidiaries absent a specific contractual undertaking by a subsidiary to pay the creditors or as required by applicable law or regulation. Similarly, Talen Energy Supply is not liable for the debts of its subsidiaries, nor are the subsidiaries liable for the debts of one another. Accordingly, creditors of these subsidiaries may not satisfy their debts from the assets of Talen Energy Supply absent a specific contractual undertaking by that parent or other subsidiary to pay such creditors or as required by applicable law or regulation.


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As indicated above, certain debt agreements, including, but not limited to, the Talen Energy Supply RCF, the First Lien Credit and Guaranty Agreement and the Amended STF Agreement, include contractual undertakings by certain Talen Energy subsidiaries to guarantee the obligations of other Talen Energy entities arising under those agreements.

Distribution Related Restrictions for Talen Energy Corporation

Certain of Talen Energy's debt agreements include covenants that could effectively restrict the payment of distributions, loans or advances, either directly to Talen Energy Corporation or to Talen Energy Supply or one of its subsidiaries. At December 31, 2015, $3.3 billion of Talen Energy Corporation subsidiaries net assets were restricted for the purposes of transferring funds to Talen Energy Corporation in the form of distributions, loans or advances.

6.  Acquisitions, Development and Divestitures

Talen Energy from time to time evaluates opportunities for potential acquisitions, divestitures and development projects.  Development projects are periodically reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.  Any resulting transactions may impact future financial results.  

Acquisitions

MACH Gen

On November 2, 2015, Talen Energy completed the acquisition of the membership interests of MACH Gen for $603 million in cash consideration (based on estimated working capital). The final cash purchase price, after post-closing adjustments, was $600 million. The purchase price was funded by a borrowing under the Talen Energy Supply RCF and cash on hand. The Term Loan B and revolving credit facility of New MACH Gen remain outstanding following the completion of the transaction. See Note 5 for additional information. MACH Gen's total generating capacity is 2,344 MW (summer rating).
The MACH Gen acquisition was accounted for as a business combination, with the identifiable tangible and intangible assets and liabilities of MACH Gen, recorded at their estimated fair values on the acquisition date. The acquisition is consistent with management's strategy of business growth, fuel type diversity and replacing the assets being divested as part of the FERC approval of the RJS Power acquisition. The following table summarizes the allocation of the purchase price to the fair values of the major classes of assets and liabilities of MACH Gen.
Current assets (a) $31
Intangible assets 3
PP&E 1,275
Short-term debt (103)
Current liabilities (28)
Long-term debt (470)
Deferred income taxes (108)
Total purchase price $600

2010
(a)
Includes gross contractual amounts of accounts receivable acquired of $9 million, which approximates fair value.

The purchase price allocation is considered by Talen Energy's management to be provisional due to pending finalization of valuations and could change materially in subsequent periods. Any changes to the provisional purchase price allocation during the measurement period that result in material changes to the consolidated financial results will be adjusted prospectively. The measurement period can extend up to a year from the date of acquisition. The items pending finalization include, but are not limited to, the valuation of PP&E, certain other assets and liabilities and deferred income taxes.

Actual operating revenues and net income of MACH Gen, since the November 2, 2015 acquisition, included in Talen Energy's results for the year ended December 31, 2015 were:
 Operating Revenues Net Income (Loss)
 $28
 $(9)

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RJS Power

On June 1, 2015, substantially contemporaneous with the spinoff by PPL to form Talen Energy, RJS Power was contributed by the Riverstone Holders to become a subsidiary of Talen Energy Supply in exchange for 44,974,658 shares of Talen Energy Corporation common stock. See Notes 1 and 3 for additional information on the spinoff and acquisition. In accordance with business combination accounting guidance, Talen Energy treated the combination with RJS Power as an acquisition and Talen Energy Supply is considered the acquirer of RJS Power. Accordingly, Talen Energy applied acquisition accounting to the assets and liabilities of RJS Power whereby the purchase price was allocated to the underlying tangible and intangible assets and liabilities based on their respective fair values as of June 1, 2015, with the remainder allocated to goodwill.

The total consideration for the acquisition was deemed to be $902 million based on the fair value of the Talen Energy Corporation common stock issued for the acquisition using the June 1, 2015 closing "when-issued" market price.

The following table summarizes the allocation of the purchase price to the fair values of the major classes of assets and liabilities of RJS, all of which represent non-cash activity excluded from the Statement of Cash Flows for the year ended December 31, 2015. The purchase price allocation is considered by Talen Energy's management to be final as of December 31, 2015.

Current assets (a) $168
Assets of discontinued operations (b) 375
PP&E 1,777
Other intangibles 46
Short-term debt (36)
Current liabilities (224)
Liabilities of discontinued operations (5)
Long-term debt (1,244)
Deferred income taxes (266)
Other noncurrent liabilities (c) (82)
Net identifiable assets acquired 509
Goodwill (d) 393
Net assets acquired $902

(a)
Includes gross contractual amount of the accounts receivable acquired of $41 million, which approximates fair value.
(b)
See Note 14 for information on impairment charges recorded during 2015 related to the Sapphire plants initial classification as assets held for sale and priordiscontinued operations. See Note 1 for additional information on the subsequent reclassification to assets held and used.
(c)
Includes $33 million of "out-of-the-money" coal contracts that will be amortized over the life of the contracts terms as the coal is consumed.
(d)
The allocation above is as of the acquisition date of June 1, 2015. As further discussed in Note 16, goodwill was fully impaired during 2015, which included the goodwill recognized in the acquisition of RJS Power.

Various purchase accounting valuation adjustments were made during the third and fourth quarters affecting certain current assets and liabilities, PP&E, other intangibles and related deferred income taxes resulting in a $5 million reduction in goodwill. The statement of income effect of these adjustments recorded during the measurement period was insignificant.

Goodwill recorded as a result of the acquisition primarily reflected synergies expected to be achieved related to the spinoff and acquisition. The goodwill is not deductible for income tax purposes and was assigned to the East segment. See Note 16 for additional information related to the impairment of goodwill.

Actual operating revenues and net income of RJS, since the June 1 acquisition, included in Talen Energy's results for the year ended December 31, 2015 were:
 Operating Revenues Net Income (Loss) (a)
 $528
 $(74)

(a)Includes certain asset impairments and excludes the impact of the goodwill impairment recorded in 2015 subsequent to the acquisition. See Notes 14 and 16 for information on the impairments recorded.


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Pro Forma Information for RJS Power and MACH Gen Acquisitions

Pro forma information (unaudited) for Talen Energy for the year ended December 31, as if both the RJS Power and MACH Gen acquisitions had occurred January 1, 2014, is as follows:

  Operating Revenues  Income (Loss) After Tax from Continuing Operations
2015:    
Pro forma $5,109
 $(396)
Basic and diluted earnings per share (for Talen Energy Corporation)   (3.08)
2014:    
Pro forma 6,031
 345
Basic and diluted earnings per share (for Talen Energy Corporation)   2.68

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the acquisitions taken place on the date indicated, or the future consolidated results of operations of Talen Energy. The pro forma financial information presented above has been derived from the historical consolidated financial statements of Talen Energy and MACH Gen and from the historical consolidated and combined financial statements of RJS Power.

The pro forma financial information presented above includes adjustments for (1) alignment of accounting policies, (2) incremental depreciation and amortization expense related to fair value adjustments to PP&E and identifiable intangible assets and liabilities, (3) incremental interest expense for outstanding borrowings to reflect the terms of the Talen Energy Supply RCF related to the RJS acquisition, (4) nonrecurring items (discussed below), (5) the tax effect of the above adjustments, and (6) the issuance of Talen Energy Corporation common stock in connection with the spinoff from PPL and the acquisition of RJS Power. The pro forma financial information presented includes the impact of impairments recorded during the third and fourth quarters of 2015. See Notes 14 and 16 for information on the impairments recorded.

Nonrecurring acquisition, integration and other costs directly related to the acquisitions of $20 million were incurred during 2015 and recorded in "Operation and maintenance" on the Statements of Income. Adjustments were made in the calculation of pro forma amounts to remove the effect of these nonrecurring items and related income taxes. The pro forma financial information does not include adjustments for potential future cost savings for either acquisition.

Divestitures

Talen Renewable Energy

In November 2015, Talen Energy completed the sale of Talen Renewable Energy for $116 million in cash and recorded a pre-tax gain on the sale of $10 million in the East segment, which is reflected in "Operation and maintenance" on the Statement of Income.

Announced Divestitures

Ironwood, Holtwood, Lake Wallenpaupack and C.P. Crane Power Plants

In October 2015, Holtwood, LLC, a wholly owned, indirect subsidiary of Talen Energy, entered into an agreement to sell the Holtwood and Lake Wallenpaupack hydroelectric facilities in Pennsylvania for a purchase price of $860 million, subject to customary purchase price adjustments. The facilities have a combined summer rating operating capacity of 308 MW. The transaction is expected to close in March 2016, subject to customary closing conditions.

In October 2015, Talen Generation entered into an agreement to sell Talen Ironwood Holdings, LLC, which through its subsidiaries owns and operates the Ironwood natural gas combined-cycle plant in Pennsylvania, for a purchase price of $657 million, subject to customary purchase price adjustments. In connection with the sale, in January 2016, Talen Energy repaid $41 million of indebtedness, plus a customary debt make-whole premium. The Ironwood unit has a summer rating operating capacity of 660 MW. The sale transaction closed in February 2016, with an estimated gain, net of transaction costs including

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the make-whole premium on the debt, of $159 million, which will be recorded to "Operating Income" on the Statement of Income in 2016. Proceeds from the sale of Ironwood were used to repay the majority of Talen Energy's short-term debt.

In October 2015, Raven Power Marketing LLC, a wholly owned, indirect subsidiary of Talen Energy, entered into an agreement to sell C.P. Crane LLC, which owns and operates the C.P. Crane coal-fired power plant in Maryland. The C.P. Crane plant has a summer rating operating capacity of 402 MW. The transaction closed in February 2016. The transaction is not expected to have a significant impact on Talen Energy's financial condition or results of operations. See Notes 14 and 16 for information on impairments recorded in 2015 for this plant.

The sales are part of the requirement to divest certain PJM assets to satisfy a December 2014 FERC order approving the combination with RJS Power. See Note 1 for information on the FERC order.

At December 31, 2015, the major component of assets held for sale related to the sale of these businesses was primarily $936 million of PP&E which was included in the East segment. Talen Ironwood Holdings, LLC is considered an individually significant component whose pretax income (loss) attributable to Talen Energy for 2015, 2014, and 2013 was $73 million, $67 million, and $(22) million.

Discontinued Operations

Talen Montana Hydro Sale

In November 2014, Talen Montana completed the sale to NorthWestern Corporation of 633 MW of hydroelectric generating facilities located in Montana for approximately $900 million in cash.  The sale included 11 hydroelectric power facilities and related assets.

Following are the components of discontinued operations in the Statement of Income for the years ended December 31.    
  2014 2013
Operating revenues $117
 $139
Gain on the sale (pre-tax) 306
 —
Interest expense (a) 9
 12
Income (loss) before income taxes 332
 49
Income (Loss) from Discontinued Operations (net of income taxes) 223
 32

(a)Represents allocated interest expense based upon the discontinued operations share of the net assets of Talen Energy.  

Other

To facilitate the sale of the Montana hydroelectric generating facilities discussed above, Talen Montana terminated, in December 2013, its operating lease arrangement related to partial interests in Units 1, 2 and 3 of the Colstrip coal-fired generating facility and acquired those interests, collectively, for $271 million. At lease termination, the existing lease-related assets on the balance sheet consisting primarily of prepaid rent and leasehold improvements were written off and the acquired Colstrip assets were recorded at fair value as of the acquisition date. Talen Energy recorded a charge of $697 million ($413 million after-tax) for the termination of the lease included in "Loss on lease termination" on the 2013 Statements of Income. The $271 million payment is reflected in "Cash Flows from Operating Activities" on the 2013 Statement of Cash Flow.

Development

Bell Bend COLA

In 2008, a Talen Energy subsidiary, Bell Bend, LLC (Bell Bend) submitted a COLA to the NRC for the proposed Bell Bend nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna plant.

Also in 2008, Bell Bend submitted Parts I and II of an application for a federal loan guarantee for Bell Bend to the DOE. In February 2014, the DOE announced the first loan guarantee for a nuclear project in Georgia. Although eight of the ten applicants that submitted Part II applications remain active in the DOE program, the DOE has stated that the $18.5 billion currently appropriated to support new nuclear projects would not likely be enough for more than three projects. Bell Bend submits quarterly application updates for Bell Bend to the DOE to remain active in the loan guarantee application process.

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The NRC continues to review the COLA. Bell Bend does not expect to complete the COLA review process with the NRC prior to 2018. Bell Bend has made no decision to proceed with construction and expects that such decision will not be made for several years given the anticipated lengthy NRC license approval process. Additionally, Bell Bend does not expect to proceed with construction absent favorable economics, a joint arrangement with other interested parties and a federal loan guarantee or other acceptable financing. Bell Bend is currently authorized by Talen Energy Corporation's Board of Directors to spend up to $256 million on the COLA and other permitting costs necessary for construction. At December 31, 2015 and 2014, $201 million and $188 million of costs, which includes capitalized interest, associated with the licensing application were capitalized and are included on the Balance Sheets in noncurrent "Other intangibles." Talen Energy continues to support the Bell Bend licensing project with a near term focus on obtaining the final environmental impact statement. Talen Energy placed the NRC safety review (which supports issuance of their final safety evaluation report, the other key element of the COLA) on hold in 2014, due to a lack of progress by the reactor vendor with respect to its NRC design certification process, which is a prerequisite to the COLA.

Brunner Island Co-firing Project

Talen Energy is in the process of making modifications to its Brunner Island coal-fired generating facility to be able to co-fire using natural gas to better position the plant for low gas price environments. Construction is under way and is expected to be completed by the end of 2016. The project is expected to cost $118 million. At December 31, 2015 and 2014, $23 million and $5 million of costs, which include capitalized interest, associated with the project were capitalized and are included in "Construction work in progress" on the Balance Sheets.

7. Leases

Talen Energy and its subsidiaries have entered into various agreements for the lease of office space, vehicles, land, gas storage and other equipment. At December 31, 2015, Talen Energy's most significant lease, which expires in 2018, relates to its corporate headquarters.

Rent expense for the years ended December 31 for operating leases was as follows:
 2015 2014 2013
 $14
 $29
 $55

Total future minimum rental payments for all operating leases are estimated to be:
2016 2017 2018 2019 2020 Thereafter Total
$19
 $18
 $8
 $5
 $5
 $26
 $81

8.  Stock-Based Compensation

Stock Incentive Plan

Talen Energy Corporation grants share-based compensation to eligible participants under the Talen Energy Stock Incentive Plan (SIP). Under the SIP, restricted shares of Talen Energy Corporation stock, restricted stock units, performance units, stock options and stock appreciation rights may be granted to officers, directors and other key employees. Additionally, Talen Energy Corporation will match shares of its common stock purchased by certain employees on the open market from June 1, 2015 through March 31, 2018 with grants of restricted stock units, subject to certain restrictions (Matching Grants). Awards under the SIP are made by the Compensation, Governance and Nominating Committee (CGNC) of the Talen Energy Corporation Board of Directors or its delegate.

The total number of shares which may be issued under the plan is 5,630,000 and the maximum number of shares for which stock options may be granted is 2,000,000. Shares delivered under the SIP may be in the form of authorized and unissued Talen Energy Corporation common stock or common stock held in treasury by Talen Energy Corporation.

Restricted Stock Units

Restricted stock units are awards based on the fair value of a share of Talen Energy Corporation common stock on the date of grant. Actual Talen Energy Corporation common shares will be issued upon completion of a vesting period of three years,

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aside from Matching Grants that generally vest two years from the date of grant. Substantially all restricted stock unit awards are expected to vest.

The fair value of restricted stock units granted is recognized as compensation expense on a straight-line basis over the service period. Restricted stock units are subject to forfeiture or accelerated payout under the pertinent award agreement provisions for termination, disability and death of employees. Restricted stock units vest fully, in certain situations, as defined by in the applicable award agreement. The total restricted stock units granted, nonvested and outstanding through December 31, 2015 was 265,849 and the weighted-average grant date fair value per share was $18.74.

Stock Options

Stock options have been granted with an option exercise price per share not less than the fair value of Talen Energy Corporation's common stock on the date of grant. Options become exercisable in equal installments over a three-year service period beginning one year after the date of grant, assuming the individual is still employed by Talen Energy or a subsidiary. The CGNC has discretion to accelerate the exercisability of the options. All options expire no later than ten years from the grant date. The options become exercisable immediately in certain situations, as defined by the pertinent award agreement. The fair value of options granted is recognized as compensation expense on a straight-line basis over the service period. Substantially all stock option awards are expected to vest. The total stock options granted, nonvested and outstanding through December 31, 2015 was 991,101 and the grant date fair value per share was $4.91. The weighted-average exercise price per share is $19.00 and the weighted-average remaining contractual term is 9.4 years. The stock options outstanding at December 31, 2015 are currently out of the money.
The fair value of each option granted is estimated using a Black-Scholes option-pricing model. Talen Energy uses a risk-free interest rate, expected option life and expected volatility to value its stock options. Talen Energy Corporation does not currently expect to pay dividends, therefore a dividend yield assumption is not used to value stock options. The risk-free interest rate reflects the yield for a U.S. Treasury Strip available on the date of grant with constant rate maturity approximating the option's expected life. Expected life was calculated using the simplified method described in SEC Staff Accounting Bulletin (SAB) 107/110 (updated by SAB 110). Expected volatility is derived from the historical volatility of a peer group selected by management as Talen Energy Corporation's common stock does not have a trading history.

The assumptions used in the model were:
Risk-free interest rate2.05%
Expected option life6.00 years
Expected stock volatility21.55%

Performance Units

Performance units represent a target number of shares of Talen Energy Corporation's common stock that the recipient would receive upon Talen Energy Corporation's attainment of an applicable performance goal. For awards granted in 2015, Talen Energy Corporation uses TSR, which is determined based on TSR during a three-year performance period. At the end of the performance period, payout is determined by comparing Talen Energy Corporation's TSR to the TSR of peer group companies that Talen Energy Corporation has selected. Awards are payable on a graduated basis, based on thresholds that measure Talen Energy Corporation's performance relative to the peer group companies, on which each years' awards are measured. Awards can be paid up to 200% of the target award or forfeited with no payout if performance is below a minimum established performance threshold. Under the pertinent award agreement provisions, performance units are subject to forfeiture upon termination of employment except for in the event of a disability or death of an employee, in which case the total performance units remain outstanding and are eligible for vesting through the conclusion of the performance period. The fair value of performance units is recognized as compensation expense on a straight-line basis over the three-year performance period. Performance units vest on a pro rata basis, in certain situations, as defined by the applicable award agreement.

The fair value of performance units granted was estimated using a Monte Carlo pricing model that values market based performance conditions such as TSR. The model assumed an expected stock volatility of 31.8% that was based on the historical volatility based on daily stock price changes of peer group companies.

The total performance units granted, nonvested and outstanding through December 31, 2015 was 158,900 and the weighted-average grant date fair value was $21.17 per share.


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Directors Deferred Compensation Plan

Under the Talen Energy Corporation Directors Deferred Compensation Plan, or DDCP, stock units are granted to eligible directors of Talen Energy Corporation in connection with their retainers for service on Talen Energy Corporation’s board of directors and its committees. Stock units are based on the fair market value of a share of Talen Energy Corporation’s common stock on the date of grant. The total number of stock units granted under the DDCP through December 31, 2015 was 34,967 and the weighted average grant date fair value was $13.23 per share.

Compensation Expense

The year ended December 31, 2015 includes an insignificant amount of compensation expense for Talen Energy Corporation restricted stock units, performance units and stock options accounted for as equity awards.

The year ended December 31, 2014 includes compensation expense of $33 million and the associated income tax benefit of $14 million for restricted stock, restricted stock units, performance units and stock options accounted for as equity awards from PPL, which included an allocation of PPL Services' expense.

The year ended December 31, 2013 includes compensation expense of $27 million and the associated income tax benefit of $11 million for restricted stock, restricted stock units, performance units and stock options accounted for as equity awards from PPL, which included an allocation of PPL Services' expense.
At December 31, 2015, unrecognized compensation expense and the weighted-average period for recognition related to nonvested restricted stock units, performance units and stock option awards from Talen Energy was $11 million and 2.4 years.
Prior to the spinoff, restricted shares of PPL common stock and related restricted stock units, performance units and stock options were granted to officers and other key employees of Talen Energy. At December 31, 2014, these employees of Talen Energy had 1,457,900 of unvested shares of restricted stock and restricted stock units, 291,492 of performance units and 2,745,016 of outstanding stock options issued by PPL. The vesting of these awards was accelerated in 2015 in connection with the spinoff from PPL. See Note 1 for information on the recording of expense related to this acceleration and additional information on the spinoff from PPL. For the year ended December 31, 2015, compensation expense for these awards, excluding the acceleration, but including an allocation of PPL Services' compensation expense for similar awards, was $18 million.

9.  Retirement and Postemployment Benefits

Prior to the June 1, 2015 spinoff, the majority of Talen Energy Supply's employees were eligible for pension benefits under a PPL non-contributory defined benefit pension plan, with benefits based on length of service and either career average pay or final average pay, as defined by the plan. Prior to the June 1, 2015 spinoff, this plan was closed to all newly hired employees. Newly hired employees were eligible to participate in a PPL 401(k) savings plan with enhanced employer contributions. Talen Energy was allocated costs of the PPL pension plan based on its employees' participation in the plan. Employees who participated in this PPL pension plan who became employees of Talen Energy Supply transferred into a newly created pension plan sponsored by Talen Energy Supply, which provides benefits similar to that of the PPL pension plan.

Prior to the June 1, 2015 spinoff, the majority of Talen Energy Supply's employees were also eligible for certain health care and life insurance benefits upon retirement through the PPL other postretirement benefit plans, which prior to June 1, 2015, were closed to all newly hired employees. Talen Energy Supply was allocated costs of the PPL plans based on its employees' participation in the plans. Employees who participated in the health care and life insurance plans and who became employees of Talen Energy Supply transferred into the newly created Talen Energy other postretirement benefit plans sponsored by Talen Energy Supply, which provide benefits similar to those of the PPL other postretirement benefit plans.

A remeasurement of the assets and the obligations for the PPL pension and other postretirement benefit plans was performed as of May 31, 2015 in order to separate the assets and obligations of the PPL plans attributable to Talen Energy, as required by the spinoff agreements. The Talen Energy pension plan assumed from PPL the pension benefit obligations for active plan participants who became employees of Talen Energy in connection with the spinoff and for individuals who terminated employment from Talen Energy Supply on or after July 1, 2000. A portion of the PPL pension plan assets were also allocated to the new Talen Energy pension plan. The asset allocation was based on the rules prescribed by ERISA (Employee Retirement Income Security Act) for allocating assets in connection with a pension plan spinoff. The Talen Energy other postretirement benefit plans assumed the other postretirement benefit obligations from PPL for active plan participants who became

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employees of Talen Energy in connection with the spinoff. PPL retained obligations attributable to existing retirees as of the date of the spinoff. A portion of the PPL other postretirement benefit plan assets, which were held in VEBA trusts and a 401(h) account, were also allocated to the new Talen Energy other postretirement benefit plans. The asset allocation was determined separately for each funding vehicle based on the ratio of the accumulated postretirement benefit obligation (APBO) assumed by Talen Energy to the total APBO attributed to each funding vehicle. As a result of the above, the net funded status of the new Talen Energy pension and other postretirement benefit plans at June 1, 2015 was a liability of $257 million.

The majority of Talen Montana's employees are eligible for pension benefits under a cash balance plan. Effective January 1, 2012, that plan was closed to all newly hired salaried employees. Effective September 1, 2014, that plan was closed to all newly hired bargaining unit employees. Newly hired employees are eligible to participate in a 401(k) savings plan with enhanced employer contributions. The majority of Talen Montana's employees are also eligible for certain health care and life insurance benefits upon retirement, under a retiree health plan sponsored by Talen Montana, which is now closed to newly hired employees. There were no changes to the pension and other postretirement benefit plans for employees of Talen Montana as a result of the spinoff transaction. However, PPL retained the liability for other postretirement benefits attributable to existing retirees of Talen Montana as of the date of the spinoff.

Employees of certain of Talen Energy's mechanical contracting companies are eligible for benefits under multiemployer plans sponsored by various unions.

The following table provides the components of net periodic defined benefit costs for Talen Energy pension and other postretirement plans for the years ended December 31, for which the 2015 periods include seven months of costs under the newly formed Talen Energy plans and a full year of Talen Montana plans.
 Pension Benefits Other Postretirement Benefits
 2015
2014
2013 2015 2014 2013
Net periodic defined benefit costs (credits):           
Service cost$31
 $5
 $7
 $2
 $—
 $1
Interest cost46
 9
 8
 2
 1
 —
Expected return on plan assets(60) (11) (10) (3) —
 —
Amortization of:           
Actuarial (gain) loss16
 2
 3
 —
 —
 —
Curtailment charges (credits)—
 —
 —
 —
 (1) —
Net periodic defined benefit costs (credits)$33

$5

$8

$1

$—

$1
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
Other changes in plan assets and benefit obligations recognized in OCI:           
Curtailments$—
 $—
 $—
 $—
 $1
 $—
Net (gain) loss54
 26
 (15) —
 (1) (1)
Prior service cost (credit)3
 —
 —
 —
 —
 (3)
Amortization of:           
Actuarial gain (loss)(16) (2) (3) —
 —
 —
Prior service credit (cost)—
 —
 —
 1
 —
 —
Total recognized in OCI41
 24
 (18) 1
 —
 (4)
Total recognized in net periodic defined benefit costs and OCI$74
 $29
 $(10) $2
 $—
 $(3)

Actuarial loss of $20 million related to these plans is expected to be amortized from AOCI into net periodic defined benefit costs in 2016.

The following net periodic defined benefit costs (credits) were charged to operating expense, excluding amounts charged to construction and other non-expense accounts.

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 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
 $48
 $39
 $45
 $2
 $3
 $6

In the table above, amounts include costs for the specific plans sponsored by Talen Energy and its subsidiaries and the following allocated costs of the PPL pension and other postretirement benefit plans prior to the spinoff, based on Talen Energy Supply's participation in those plans, which management believes were reasonable at the time:
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
 $16
 $34
 $38
 $—
 $3
 $5

At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors adopted the mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables) for all applicable defined benefit pension and other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors also selected the IRS BB 2-Dimensional mortality improvement scale on a generational basis for all applicable defined benefit pension and other postretirement benefit plans. These mortality assumptions reflect the recognition of both improved life expectancies and the expectation of continuing improvements in life expectancies.

The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2015 2014
Discount rate4.65% 4.28% 4.60% 3.81%
Rate of compensation increase3.98% 4.03% 3.98% 4.03%

The following weighted-average assumptions were used to determine the net periodic defined benefit costs for Talen Energy's plans for the years ended December 31.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
Discount rate4.41% 5.18% 4.25% 4.27% 4.51% 3.77%
Rate of compensation increase3.99% 3.94% 3.95% 3.99% 3.94% 3.95%
Expected return on plan assets (a)7.00% 7.00% 7.00% 6.37% N/A
 N/A
(a)The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
The following table provides the assumed health care cost trend rates for the years ended December 31.
 2015 2014 2013
Health care cost trend rate assumed for next year     
obligations6.80% 7.20% 7.60%
costs7.20% 7.60% 8.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)     
obligations5.00% 5.00% 5.00%
costs5.00% 5.00% 5.50%
Year that the rate reaches the ultimate trend rate     
obligations2020
 2020
 2020
costs2020
 2020
 2019

A one percentage point change in the assumed health care costs trend rate assumption would have been insignificant to the other postretirement benefit plans in 2015.
    

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The funded status of Talen Energy's plans at December 31 was as follows:
 Pension Benefits Other Postretirement Benefits
 2015 2014 2015 2014
Change in Benefit Obligation       
Benefit obligation, beginning of period$210
 $163
 $10
 $12
Transfer of benefit obligation at spinoff (a)1,416
 —
 80
 —
Service cost31
 5
 2
 —
Interest cost46
 9
 2
 1
Plan amendments3
 —
 —
 —
Actuarial (gain) loss(41) 38
 (4) (1)
Net Transfers in (out)—
 —
 (3) —
Curtailments—
 —
 —
 (1)
Gross benefits paid(51) (5) —
 (1)
Benefit obligation, end of period$1,614
 $210
 $87
 $10
        
Change in Plan Assets       
Plan assets at fair value, beginning of period$170
 $147
 $—
 $—
Transfer of plan assets at fair value at spinoff (a)1,159
 —
 80
 —
Actual return on plan assets(35) 22
 (2) —
Employer contributions32
 6
 1
 1
Gross benefits paid(52) (5) (1) (1)
Plan assets at fair value, end of period1,274
 170
 78
 —
Funded status end of period$(340) $(40) $(9) $(10)
        
Amounts recognized in the Balance Sheets consist of:       
Current Liability$—
 $—
 $—
 $(1)
Noncurrent liability(340) (40) (9) (9)
Net amount recognized, end of period$(340) $(40) $(9) $(10)
        
Amounts recognized in AOCI (pre-tax) consist of:       
Prior service cost (credit)$2
 $—
 $(5) $(4)
Net actuarial (gain) loss451
 59
 8
 —
Total$453
 $59
 $3
 $(4)
        
Total accumulated benefit obligation for defined benefit pension plans$1,500
 $210
 
 

(a)For LKE, LG&E and KU 2009,Values determined as wellof the spinoff date as the ten month period ending October 31, 2010, remain open under the standard three year statute of limitations; however, the IRS has completed its audit of these periods under the Compliance Assurance Process, effectively closing them to audit adjustments.  No issues remain outstanding.             discussed above.

Other(PPLTalen Energy's pension plans had projected and PPL Energy Supply)

PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year for Pennsylvania operations.  PPL made the same change for its Montana operations for tax year 2009.  In 2011, the IRS issued guidance on repair expenditures related to network assets providing a safe harbor method of determining whether the repair expenditures can be currently deducted for tax purposes.  The IRS has not yet issued guidance to provide a safe harbor method related to generation property.  The IRS may assert and ultimately conclude that PPL's deduction for generation-related expenditures should be disallowedaccumulated benefit obligations in whole or in part.  PPL believes that it has established an adequate reserve for this contingency.

Tax Legislation(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

On January 2, 2013, H.R. 8, The American Taxpayer Relief Act of 2012, was signed into law.  The most significant extension of tax relief under this Act applicable to PPL is the extension of bonus depreciation.  This provision extends the current 50% expensing provision for qualifying property purchased and placed in service before January 1, 2014 (before January 1, 2015 for certain longer-lived and transportation assets).  PPL is still evaluating the changes.  However, PPL does not expect that the changes related to this legislation will have a material impact on income tax expense.    
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6.  Utility Rate Regulation

Regulatory Assets and Liabilities

(PPL, PPL Electric, LKE, LG&E and KU)

As discussed in Note 1 and summarized below, PPL, PPL Electric, LKE, LG&E and KU reflect the effects of regulatory actions in the financial statements for their cost-based rate-regulated utility operations.  Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date.  As such, the primary items classified as current are related to rate mechanisms that periodically adjust to account for over- or under-collections.

(PPL, LKE, LG&E and KU)

LG&E is subject to the jurisdiction of the KPSC and FERC, and KU is subject to the jurisdiction of the KPSC, FERC, VSCC and TRA.

LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms.  As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.

As a result of purchase accounting requirements, certain fair value amounts related to contracts that had favorable or unfavorable terms relative to market were recorded on the Balance Sheets with an offsetting regulatory asset or liability.  LG&E and KU recover in customer rates the cost of coal contracts, power purchases and emission allowances.  As a result, management believes the regulatory assets and liabilities created to offset the fair value amounts at LKE's acquisition date meet the recognition criteria established by existing accounting guidance and eliminate any rate making impactexcess of the fair value adjustments.  LG&E'sof plan assets at December 31, 2015 and KU's customer rates will continue to reflect the original contracted prices for these contracts.2014.

(In addition to the plans it sponsors, Talen Energy Supply and its subsidiaries were allocated a portion of the funded status and costs of the defined benefit plans sponsored by PPL LKEServices based on their participation in those plans prior to the spinoff, which management believes were reasonable at that time. The actuarially determined obligations of current active employees were used as a basis to allocate total plan activity, including active and KU)retiree costs and obligations. Allocations to Talen Energy Supply resulted in liabilities at December 31, 2014 as follows:
Pension plans$259
Other postretirement benefit plans34

KU's Virginia base ratesTalen Energy's mechanical contracting subsidiaries make contributions to over 60 multiemployer pension plans, based on the bargaining units from which labor is procured. The risks of participating in these multiemployer plans are calculateddifferent from single-employer plans in the following aspects:


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Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.

If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

If Talen Energy's mechanical contracting subsidiaries choose to stop participating in some of their multiemployer plans, they may be required to pay those plans an amount based on the unfunded status of the plan, referred to as a withdrawal liability.

Talen Energy identified the Steamfitters Local Union No. 420 Pension Plan, EIN/Plan Number 23-2004424/001 as the plan to which the most significant contributions are made. Contributions to this plan by Talen Energy's mechanical contracting companies were $5 million for 2015, 2014 and 2013. At the date the financial statements were issued, the Form 5500 was not available for the plan year ending in 2015. Therefore, the following disclosures specific to this plan are being made based on the Form 5500s filed for the plan years ended December 31, 2014 and 2013. Talen Energy's mechanical contracting subsidiary H.T. Lyons was identified individually as a greater than 5% contributor on the Form 5500s. The plan had a Pension Protection Act zone status of red, without utilizing an extended amortization period, as of December 31, 2014 and 2013. In addition, the plan is subject to a rehabilitation plan and surcharges have been applied to participating employer contributions. The expiration date of the collective-bargaining agreement related to those employees participating in this plan is September 18, 2016. There were no other plans deemed individually significant based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions).  All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.multifaceted assessment.

KU's ratesTalen Energy's mechanical contracting subsidiaries also participate in multiemployer other postretirement plans that provide for retiree life insurance and health benefits.

The table below details total contributions to municipal customers for wholesale requirements are calculatedall multiemployer pension and other postretirement plans, including the plan identified as significant above. The contribution amounts fluctuate each year based on annual updatesthe volume of work and type of projects undertaken from year to year.
 2015 2014 2013
Pension plans$34
 $40
 $36
Other postretirement benefit plans26
 33
 32
Total contributions$60
 $73
 $68

Plan Assets

At December 31, 2015, Talen Energy's pension plans are invested in the Talen Energy Retirement Plans Master Trust (the Master Trust) that also includes a rate formula401(h) account that utilizesis restricted for certain other postretirement benefit obligations of Talen Energy. Prior to the spinoff from PPL, the pension plan assets were invested by PPL in a master trust maintained by PPL.

The investment strategy for the Master Trust is to achieve a risk-adjusted return on a mix of assets that, in combination with Talen Energy's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments, while also managing the duration of the assets to complement the duration of the liabilities. The Master Trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore has no significant concentration of risk.

The investment policy of the Master Trust outlines investment objectives and defines the responsibilities of the Retirement Plan Committee of Talen Energy Corporation, which is the named fiduciary, external investment managers, investment advisor and trustee and custodian. The investment policy is reviewed annually by Talen Energy Corporation's Board of Directors.

The Retirement Plan Committee created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios: growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return on rate base (net utility plant plus working capital less deferred taxesat a reasonable risk, including equity securities, certain debt securities and miscellaneous deductions).  All regulatory assetsalternative investments. The immunizing portfolio consists of debt securities, generally with long durations, and liabilities are excluded fromderivative positions. The immunizing portfolio is designed to offset a portion of the return on rate base utilizedchange in the developmentpension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of municipal rates; therefore, no returncash and cash equivalents.

Target asset allocation ranges have been developed for the Master Trust based on input from external consultants with a goal of limiting funded status volatility. The Retirement Plan Committee monitors the investments in the Master Trust, and seeks to

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obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the Retirement Plan Committee establishes revised guidelines from time to time.

The asset allocation for the trust and the target allocation prescribed by the investment guidelines by portfolio at December 31 are as follows:
 Percentage of trust assets Target Asset Allocation
 2015 2015
Growth Portfolio52% 55%
Equity securities24%  
Debt securities (a)14%  
Alternative investments14%  
Immunizing Portfolio46%
44%
Debt securities (a)40%  
Derivatives6%  
Liquidity Portfolio2% 1%
Total100%
100%
(a)Includes commingled debt funds, which Talen Energy treats as debt securities for asset allocation purposes.

Prior to the spinoff, the assets of the Talen Montana pension plan were invested solely in a master trust maintained by PPL. The fair value of this plan's assets of $170 million at December 31, 2014 represented an interest of approximately 4% in PPL's master trust.

The fair value of net assets in the Master Trust by asset class and level within the fair value hierarchy was:
 December 31, 2015
 Fair Value Measurement Using
 Total Level 1 Level 2 Level 3
Talen Energy Retirement Plans Master Trust       
Cash and cash equivalents$108
 $108
 $—
 $—
Equity securities:
      
U.S.:
      
Large-cap90
 23
 67
 —
Small-cap33
 33
 —
 —
International190
 —
 190
 —
Commingled debt273
 —
 273
 —
Debt securities:
      
U.S. Treasury and U.S. government sponsored agency192
 189
 3
 —
Corporate231
 —
 231
 —
International government1
 —
 1
 —
Other3
 —
 3
 —
Alternative investments:
      
Commodities28
 —
 28
 —
Real estate48
 —
 48
 —
Private equity31
 —
 —
 31
Hedge funds69
 —
 69
 —
Derivatives:
      
Interest rate swaps32
 —
 32
 —
Other5
 —
 5
 —
Talen Energy Retirement Plans Master Trust assets, at fair value$1,334

$353

$950

$31
        
Receivables and payables, net (a)(31)      
401(h) accounts restricted for other postretirement benefit obligations(29)      
Total Talen Energy Retirement Plans Master Trust pension assets$1,274
      
(a)Receivables and payables represent amounts for investments sold/purchased, but not yet settled along with interest and dividends earned, but not yet received.

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A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2015 is earnedas follows:
 
Private
equity
Balance at beginning of period$—
Acquisitions (a)35
Purchases, sales and settlements(4)
Balance at end of period$31
(a)Transferred from a master trust maintained by PPL.

The fair value measurements of cash and cash equivalents are based on the related assets.amounts on deposit.

(PPLThe market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and PPL Electric)passively managed investments that are managed against various equity indices.

PPL Electric's distribution baseInvestments in commingled equity and debt funds are categorized as equity securities and are classified as Level 2. The fair value measurements for Level 2 investments are based on firm quotes of net asset values per share, which are not considered obtained from a quoted price in an active market. Investments in commingled equity funds include funds that invest in U.S. and international equity securities. Investments in commingled debt funds include funds that invest in a diversified portfolio of emerging market debt obligations, as well as funds that invest in investment grade long-duration fixed-income securities.

The fair value measurements of debt securities are generally based on evaluations that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. The fair value of debt securities is generally measured using a market approach, including the use of pricing models which incorporate observable inputs. Common inputs include benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as payment data, future predicted cash flows, collateral performance and new issue data. For the Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries and investments in debt securities issued by foreign governments and corporations.

Investments in commodities represent ownership interest of a commingled fund that is invested in a portfolio of exchange-traded futures and forward contracts in commodities to obtain broad exposure to all principal groups in the global commodity markets, including energy, agriculture, livestock and metals (both precious and industrial) using proprietary commodity trading strategies. Redemptions can be made the 15th calendar day and last calendar day of the month with a specified notification period. The fund's fair value is based upon a value as calculated by the fund's administrator.

Investments in real estate represent an investment in a partnership whose purpose is to manage investments in core U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The manager is focused on properties with high occupancy rates with quality tenants. This results in a focus on high income and stable cash flows with appreciation being a secondary factor. Core real estate generally has a lower degree of leverage when compared with more speculative real estate investing strategies. The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value.

Investments in private equity represent interests in partnerships in private equity fund of funds that use a number of diverse investment strategies. Two of the partnerships have limited lives of ten years, while the third has a life of 15 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. The Master Trust has unfunded commitments of $12 million that may be required during the lives of the partnerships. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.

Investments in hedge funds represent investments in three hedge fund of funds. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver

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positive returns under most market conditions. Major investment strategies for the hedge fund of funds include long/short equity, market neutral, distressed debt, and relative value. Generally, shares may be redeemed within 60 to 95 days with prior written notice. The funds are calculatedsubject to short term lockups and have limitations on the amount that may be withdrawn based on a returnpercentage of the total net asset value of the fund, among other restrictions. All withdrawals are subject to the general partner's approval. The fair value for two of the funds has been estimated using the net asset value per share and the third fund's fair value is based on rate base (net utility plant plusan ownership interest in partners' capital to which a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions).  PPL Electric's transmission revenues are billed in accordance with a FERC tariff that allows for recoveryproportionate share of transmission costs incurred, a return on transmission-related plant and an automatic annual update.  See "Transmission Formula Rate" below for additional information on this tariff.  All regulatorynet assets and liabilities are excluded from distribution and transmission return on investment calculations; therefore, generally no return is earned on PPL Electric's regulatory assets.

(PPL, PPL Electric, LKE, LG&E and KU)attributed.

The following tables provide information aboutfair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard industry models. These instruments primarily include interest rate swaps, which are valued based on the regulatory assetsswap details, such as swap curves, notional amount, index and liabilitiesterm of cost-based rate-regulated utility operations.
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   PPL PPL Electric
   2012  2011  2012  2011 
              
Current Regulatory Assets:            
 Gas supply clause $ 11  $ 6       
 Fuel adjustment clause   6    3       
 Other   2          
Total current regulatory assets $ 19  $ 9       
              
Noncurrent Regulatory Assets:            
 Defined benefit plans $ 730  $ 615  $ 362  $ 276 
 Taxes recoverable through future rates   293    289    293    289 
 Storm costs   168    154    59    31 
 Unamortized loss on debt   96    110    65    77 
 Interest rate swaps   67    69       
 Accumulated cost of removal of utility plant   71    53    71    53 
 Coal contracts (a)   4    11       
 AROs   26    18       
 Other   28    30    3    3 
Total noncurrent regulatory assets $ 1,483  $ 1,349  $ 853  $ 729 
             
Current Regulatory Liabilities:            
 Generation supply charge $ 27  $ 42  $ 27  $ 42 
 ECR   4    7       
 Gas supply clause   4    6       
 Transmission service charge   6    2    6    2 
 Transmission formula rate      5       5 
 Universal Service Rider   17    1    17    1 
 Other   3    10    2    3 
Total current regulatory liabilities $ 61  $ 73  $ 52  $ 53 
              
Noncurrent Regulatory Liabilities:            
 Accumulated cost of removal of utility plant $ 679  $ 651       
 Coal contracts (a)   141    180       
 Power purchase agreement - OVEC (a)   108    116       
 Net deferred tax assets   34    39       
 Act 129 compliance rider   8    7  $ 8  $ 7 
 Defined benefit plans   17    9       
 Interest rate swaps   14          
 Other   9    8       
Total noncurrent regulatory liabilities $ 1,010  $ 1,010  $ 8  $ 7 

   LKE LG&E KU
   2012  2011  2012  2011  2012  2011 
                    
Current Regulatory Assets:                  
 Gas supply clause $ 11  $ 6  $ 11  $ 6       
 Fuel adjustment clause   6    3    6    3       
 Other   2       2          
Total current regulatory assets $ 19  $ 9  $ 19  $ 9       
                    
Noncurrent Regulatory Assets:                  
 Defined benefit plans $ 368  $ 339  $ 232  $ 225  $ 136  $ 114 
 Storm costs   109    123    59    66    50    57 
 Unamortized loss on debt   31    33    20    21    11    12 
 Interest rate swaps   67    69    67    69       
 Coal contracts (a)   4    11    2    5    2    6 
 AROs   26    18    15    11    11    7 
 Other   25    27    5    6    20    21 
Total noncurrent regulatory assets $ 630  $ 620  $ 400  $ 403  $ 230  $ 217 
                   
 Current Regulatory Liabilities:                  
  ECR $ 4  $ 7        $ 4  $ 7 
  Gas supply clause   4    6  $ 4  $ 6       
  Other   1    7       4    1    3 
Total current regulatory liabilities $ 9  $ 20  $ 4  $ 10  $ 5  $ 10 
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   LKE LG&E KU
   2012  2011  2012  2011  2012  2011 
Noncurrent Regulatory Liabilities:                  
 Accumulated cost of removal                  
  of utility plant $ 679  $ 651  $ 297  $ 286  $ 382  $ 365 
 Coal contracts (a)   141    180    61    78    80    102 
 Power purchase agreement - OVEC (a)   108    116    75    80    33    36 
 Net deferred tax assets   34    39    28    31    6    8 
 Defined benefit plans   17    9          17    9 
 Interest rate swaps   14       7       7    
 Other   9    8    3    3    6    5 
Total noncurrent regulatory liabilities $ 1,002  $ 1,003  $ 471  $ 478  $ 531  $ 525 

(a)
These regulatory assets and liabilities were recorded as offsets to certain intangible assets and liabilities that were recorded at fair value upon the acquisition of LKE.                    
index, reset frequency and payer/receiver credit ratings.

Following is an overview of selected regulatory assets and liabilities detailed in the preceding tables.  Specific developments with respect to certain of these regulatory assets and liabilities are discussed in "Regulatory Matters."Plan Assets - Other Postretirement Benefit Plans

(Prior to the spinoff from PPL, the other postretirement benefit plan assets were invested by PPL in VEBA trusts and PPL Electric)

Generation Supply Chargea 401(h) account, maintained by PPL.

The generation supply chargeinvestment strategy with respect to other postretirement benefit obligations is to fund VEBA trusts and/or 401(h) accounts with voluntary contributions, when appropriate, and to invest in a cost recovery mechanismtax efficient manner. Excluding the 401(h) accounts included in the Master Trust, other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that permits PPL Electric to recover costs incurred to provide generation supply to PLR customers who receive basic generation supply service.liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities, but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes. The recovery includes chargesasset allocation for generation supply (energythe VEBA trusts and capacitythe target allocation, by asset class, at December 31 are detailed below.
 Percentage of plan assetsTarget Asset Allocation
 2015 2015
Asset Class   
U.S. Equity securities53% 45%
Debt securities46% 50%
Cash and cash equivalents1% 5%
Total100% 100%

The fair value of assets in the other postretirement benefit plans by asset class and ancillary services),level within the fair value hierarchy was:
 December 31, 2015
 Fair Value Measurement Using
 Total Level 1 Level 2 Level 3
U.S. Equity securities:
      
Large-cap$26
 $—
 $26
 $—
Commingled debt23
 —
 23
 —
Total VEBA trust assets, at fair value49
 $—
 $49
 $—
401(h) account assets29
      
Total other postretirement benefit plan assets$78
      

Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Fair value measurements are not obtained from a quoted price in an active market but are based on firm quotes of net asset values per share as well as administrationprovided by the trustee of the acquisition process.  In addition, the generation supply charge contains a reconciliation mechanism whereby any over- or under-recovery from prior quarters is refunded to, or recovered from, customers through the adjustment factor determined for the subsequent quarter.fund. Redemptions can be made daily on this fund.

Universal Service Rider (USR)Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade long-duration fixed income securities. Redemptions can be made weekly on these funds.


PPL Electric's distribution rates permit recovery of applicable costs associated with the universal service programs provided to PPL Electric's residential customers.  Universal service programs include low-income programs, such as OnTrack and Winter Relief Assistance Program (WRAP).  OnTrack is a special payment program for low-income households within the federal poverty level who have difficulty paying their electric bills.  This program is funded by residential customers and administered by community-based organizations.  Customers who participate in OnTrack receive assistance in the form of reduced payment arrangements, protection against termination of electric service and referrals to other community programs and services.  The WRAP program reduces electric bills and improves living comfort for low-income customers by providing services such as weatherization measures and energy education services.  The USR is applied to distribution charges for each customer who receives distribution service under PPL Electric's residential service rate schedules.  The USR contains a reconciliation mechanism whereby any over- or under-recovery from the current year is refunded to or recovered from residential customers through the adjustment factor determined for the subsequent year.
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Act 129 Compliance Rider

In compliance with Pennsylvania's Act 129 of 2008 and implementing regulations, PPL Electric's energy efficiency and conservation plan was approved by a PUC order in October 2009.  The order allows PPL Electric to recover the maximum $250 million cost of the program ratably over the life of the plan, from January 1, 2010 through May 31, 2013.  The plan includes programs intended to reduce electricity consumption.  The recoverable costs include direct and indirect charges, including design and development costs, general and administrative costs and applicable state evaluator costs.  The rates are applied to customers who receive distribution service through the Act 129 Compliance Rider.  The actual program costs are reconcilable, and any over- or under-recovery from customers will be refunded or recovered at the end of the program.  See below under "Regulatory MattersExpected Cash Flows - Pennsylvania Activities" for additional information on Act 129.
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Transmission Service Charge (TSC)

PPL Electric is charged by PJM for transmission service-related costs applicable to its PLR customers.  PPL Electric passes these costs on to customers, who receive basic generation supply service through the PUC-approved TSC cost recovery mechanism.  The TSC contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to, or recovered from, customers through the adjustment factor determined for the subsequent year.

Transmission Formula Rates

PPL Electric's transmission revenues are billed in accordance with a FERC-approved open access transmission tariff that utilizes a formula-based rate recovery mechanism.  The formula rate is based on prior year expenditures and forecasted current calendar year transmission plant additions.  An adjustment to the prior year expenditures is recorded as a regulatory asset or liability.

(PPL, PPL Electric, LKE, LG&E and KU)

Defined Benefit Plans

Recoverable costs ofTalen Energy Supply's defined benefit pension plans representhave the portion of unrecognized transition obligation,option to utilize available prior service costyear credit balances to meet current and net actuarial losses that will be recovered infuture contribution requirements. Talen Energy expects to contribute $40 million to its defined benefit pension plans expense throughin 2016.

Talen Energy is not required to make contributions to its other postretirement benefit plans.

The following benefit payments, which reflect expected future base rates based upon established regulatory practices and are amortized over the average service, lives of plan participants.  These regulatory assets and liabilities are adjusted at least annually or whenever the funded status of defined benefit plans is re-measured.  Of the regulatory asset and liability balances recorded, costs of $60 million for PPL, $22 million for PPL Electric, $38 million for LKE, $24 million for LG&E and $14 million for KUas appropriate, are expected to be amortized into net periodic defined benefit costspaid by the plans.
 Pension Other Postretirement Benefit Payment
2016$75
 $2
201781
 3
201887
 5
201992
 7
202098
 9
2021-2025538
 63

Savings Plans

Substantially all employees of Talen Energy are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were $16 million in 2015, $14 million in 2014 and $12 million in 2013.

Storm CostsSeparation Benefits

PPL Electric, LG&ETalen Energy Supply and KU have the abilitycertain subsidiaries provide separation benefits to request from the PUC, KPSC and VSCC the authority to treat expenses related to specific extraordinary storms as a regulatory asset and defer and amortize such costs for regulatory accounting and reporting purposes.  Once such authority is granted, PPL Electric, LG&E and KU can request recovery of those expenseseligible employees. These benefits may be provided in a base rate case.

Unamortized Loss on Debt

Unamortized loss on reacquired debt represents losses on long-term debt reacquired or redeemed that have been deferred and will be amortized and recovered over either the original life of the extinguished debt or the life of the replacement debt (in the case of refinancing).  Such costsseparations due to performance issues, loss of job related qualifications or organizational changes. Generally, applicable employees separated are being amortized through 2029eligible for PPL Electric.  Such costscash severance payments, outplacement services and a single sum payment approximating the dollar amount of premium payments that would be incurred for continuation of group health and welfare coverage. Separation benefits for certain bargaining unit employees also include enhanced pension and postretirement medical benefits. Separation benefits are being amortized through 2035 for LG&Erecorded when such amounts are probable and 2036 for PPL, LKE and KU.estimable.

Accumulated Cost of Removal of Utility Plant

LG&E and KU accrue for costs of removal through depreciation expense with an offsetting credit to a regulatory liability.  The regulatory liability is relieved as costs are incurred.  See Note 1 for additional information.a discussion of separation benefits related to the spinoff and Note 11 for a discussion of separation benefits related to the one-time voluntary retirement window offered in 2014 to certain bargaining unit employees as part of the new three-year labor agreement with IBEW local 1600. Separation benefits were not significant in 2013.


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10. Jointly Owned Facilities

PPL Electric does not accrueAt December 31, 2015 and 2014 the Talen Energy Balance Sheets reflect the owned interests in the facilities below.
 Ownership Interest Electric Plant Other Property Accumulated Depreciation Construction Work in Progress
December 31, 2015         
Generating Plants         
Susquehanna90.00% $4,791
 $—
 $3,639
 $148
Conemaugh16.25% 326
 —
 156
 7
Keystone12.34% 218
 —
 111
 3
Colstrip Units 1 & 250.00% 48
 —
 5
 2
Colstrip Units 330.00% 30
 —
 2
 3
Merill Creek Reservoir8.37% —
 22
 16
 —
          
December 31, 2014         
Generating Plants         
Susquehanna90.00% $4,746
 $—
 $3,591
 $117
Conemaugh16.25% 330
 —
 141
 2
Keystone12.34% 213
 —
 102
 2
Colstrip Units 1 & 250.00% 16
 —
 4
 3
Colstrip Unit 330.00% 16
 —
 2
 2
Merill Creek Reservoir8.37% —
 22
 15
 —

Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs of removal.  When costs of removal are incurred, PPL Electric recordsassociated with the deferral of costs as a regulatory asset.  Such deferralplants is included in ratesthe corresponding operating expenses on the Statements of Income.

Talen Montana and amortized overNorthWestern have a sharing agreement that governs each party's responsibilities and rights relating to the subsequent five-year period.           operation of Colstrip Units 3 and 4. Under the terms of that agreement, each party is responsible for 15% of the total non-coal operating and construction costs of Colstrip Units 3 and 4, regardless of whether a particular cost is specific to Colstrip Unit 3 or 4, and is entitled to take up to the same percentage of the available generation from Units 3 and 4.

11.  Commitments and Contingencies

Energy Purchase and Sales Commitments

Energy Purchase Commitments

Talen Energy enters into long-term energy and energy related contracts which include commitments to purchase:
 Contract Type
 Fuels (a) Limestone Natural Gas Storage Natural Gas Transportation Power, excluding wind RECs Wind Power
Maximum Maturity Date2027 2030 2026 2034 2021 2020 2027

(a)As a result of depressed wholesale market prices for electricity and natural gas. Talen Energy has experienced a shift in the dispatching of its generation fleet from coal-fired to combined-cycle natural gas-fired generation. This reduction in coal-fired generation output has resulted in a surplus of coal inventory at certain of Talen Energy's Pennsylvania plants. To mitigate the risk of oversupply, Talen Energy incurred pre-tax charges of $41 million during 2015 in connection with an agreement to reduce its 2015 through 2018 contracted coal deliveries. These charges were recorded to "Fuel" on the Statement of Income.

Energy Sale Commitments

(PPL, LKE, LG&E and KU)In connection with its marketing activities or hedging strategies for its power plants, Talen Energy has entered into long-term power sales contracts that extend into 2020.


ECR
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Legal Matters

Kentucky law permits LG&ELegal Proceedings

Talen Energy is involved in the following legal proceedings, claims and KUlitigation.  Talen Energy believes that it has meritorious defenses in connection with its current legal proceedings, claims and litigation, and it intends to recovervigorously contest each of them. However, there can be no assurance that it will be successful in its efforts.

No estimate of the costs,possible loss or range of loss in excess of amounts accrued, if any, can be made at this time regarding any of the matters specifically described below because the inherently unpredictable nature of legal proceedings may be exacerbated by various factors such as ongoing discovery, significant facts that are in dispute, the stage of the proceeding and the wide range of potential outcomes for any such matter. As a result, any losses actually incurred could be substantial.

Sierra Club Litigation

In March 2013, the Sierra Club and MEIC filed a complaint in the U.S. District Court, District of Montana, Billings Division against Talen Montana and the other Colstrip Steam Electric Station (Colstrip) owners: Avista Corporation, Puget Sound Energy, Portland General Electric Company, NorthWestern Corporation and PacifiCorp. Talen Montana operates Colstrip on behalf of the owners. The complaint alleged certain violations of the Clean Air Act, including New Source Review, Title V and opacity requirements and listed 39 separate claims for relief.  The complaint requested injunctive relief and civil penalties on average of $36,000 per day per violation, including a returnrequest that the owners remediate environmental damage and that $100,000 of operating expensesthe civil penalties be used for beneficial mitigation projects.

In July 2013, the Sierra Club and a returnMEIC filed an additional Notice of and on capital invested, of complyingIntent to Sue, identifying additional plant projects that are alleged not to be in compliance with the Clean Air Act and, those federal, state or local environmental requirements which apply to coal combustion wastes and by-products from coal-fired electric generating facilities.in September 2013, filed an amended complaint.  The KPSC requires reviews of the past operations of the environmental surcharge for six-month and two-year billing periods to evaluate the related charges, credits and rates of return,amended complaint dropped all claims regarding pre-2001 plant projects, as well as the plaintiffs' Title V and opacity claims.  It did, however, add claims with respect to providea number of post-2000 plant projects, which effectively increased the number of projects subject to the litigation by about 40.  Talen Montana and the other Colstrip owners filed a motion to dismiss the amended complaint in October 2013.  In May 2014, the court dismissed the plaintiffs' independent Best Available Control Technology claims and their Prevention of Significant Deterioration (PSD) claims for three projects, but denied the owners' motion to dismiss the plaintiffs' other PSD claims on statute of limitation grounds.  In August 2014, the Sierra Club and MEIC filed a second amended complaint.  This complaint includes the same causes of action articulated in the first amended complaint, but in regard to only eight projects done between 2001 and 2013.  In September 2014, the Colstrip owners filed an answer to the second amended complaint.  Discovery closed in the first quarter of 2015, and in April, the plaintiffs indicated they intend to pursue claims related to only four of the remaining projects. The magistrate judge entered an order on the parties' motions for summary judgment on December 31, 2015. The judgment dismissed two of the plaintiffs' four remaining claims and provided more preferable legal standards for the roll-in of ECR amounts to base rates each two-year period.remaining two claims. The ECR regulatory asset or liability represents the amount thatcase has been under- or over-recovered duebifurcated as to timing or adjustmentsliability and remedy, and the liability trial is currently set for May 2016. A trial date with respect to the mechanism andremedy, if there is typically recovered within 12 months.  LG&E and KU are authorized to receive a 10.63% and 10.10% return on projects associated with the 2009 and 2011 compliance plans.  As a resultfinding of the settlement agreement in the 2012
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rate case, beginning in 2013, LG&E and KU will receive a 10.25% return on all ECR projects included in the 2009 and 2011 compliance plans.liability, has not been scheduled.

Coal ContractsNotice of Intent to File Suit

AsIn October 2014, Talen Energy received a resultnotice letter from the Chesapeake Bay Foundation (CBF) alleging violations of purchase accountingthe Clean Water Act and Pennsylvania Clean Streams Law at the Brunner Island generation plant.  The letter was sent to Brunner Island, LLC and the PADEP and is intended to provide notice of the alleged violations and CBF's intent to file suit in Federal court after expiration of the 60 day statutory notice period.  Among other things, the letter alleges that Brunner Island, LLC failed to comply with the terms of its National Pollutant Discharge Elimination System permit and associated regulations related to the application of nutrient credits to the facility's discharges of nitrogen into the Susquehanna River.  The letter also alleges that PADEP has failed to ensure that credits generated from nonpoint source pollution reduction activities that Brunner Island, LLC applies to its discharges meet the eligibility and certification requirements under PADEP's nutrient trading program regulations.  If a lawsuit is filed by CBF, Talen Energy would expect CBF to seek injunctive relief, monetary penalties, fees and costs of litigation.  

Montana Regional Haze

In September 2012, the EPA Region 8 developed a regional haze Federal Implementation Plan (FIP) for Montana. The final FIP assumed no additional controls for Corette or Colstrip Units 3 and 4, but proposed stricter limits for Corette and Colstrip Units 1 and 2. Talen Montana was meeting these stricter permit limits at Corette without any significant changes to operations, although other requirements led to the suspension of operations and retirement of Corette in March 2015. The stricter limits at

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Colstrip Units 1 and 2 would require additional controls to meet more stringent nitrogen oxides and sulfur dioxide limits, the cost of which could be significant. Both Talen Montana and environmental groups appealed the final FIP to the U.S. Court of Appeals for the Ninth Circuit where oral argument was heard in May 2014. On June 9, 2015, the Ninth Circuit issued a decision that vacated as arbitrary and capricious the portions of the FIP setting stricter emissions limits for Colstrip Units 1 and 2 and Corette. The Ninth Circuit upheld the EPA's decision not to require further emissions reductions at Colstrip Units 3 and 4. The Ninth Circuit opinion requires the EPA to now reissue a FIP that is consistent with PPL's acquisitionthe opinion.

Colstrip Wastewater Facility Administrative Order on Consent

Talen Montana is party to an Administrative Order on Consent (AOC) with the MDEQ related to operation of LKE, LG&E'sthe wastewater facilities at the Colstrip power plant. In September 2012, Earthjustice, on behalf of Sierra Club, MEIC, and KU's coal contracts were recorded at fair value on the Balance Sheets with offsetsNational Wildlife Federation, filed an affidavit under Montana's Major Facility Siting Act (MFSA) that sought review of the AOC by Montana's Board of Environmental Review. Talen Montana elected to regulatory assetshave this proceeding conducted in Montana state district court, and in October 2012, Earthjustice filed a petition for those contracts with unfavorable terms relative to current market prices and offsets to regulatory liabilities for those contracts with favorable terms relative to current market prices.  These regulatory assets and liabilities are being amortized overreview in Montana state district court in Rosebud County. This matter was stayed in December 2012 pending the outcome of separate litigation where the same terms asenvironmental groups challenged the related contracts,AOC in a writ of mandamus. That litigation was resolved in May 2013 when defendants Talen Montana and MDEQ won their motions to dismiss the matter, and the environmental groups did not appeal. In April 2014, Earthjustice filed successful motions for leave to amend the petition for review and to lift the stay. Talen Montana and the MDEQ responded to the amended petition and filed partial motions to dismiss in July 2014, which expire at various times throughwere denied in October 2014. Discovery closed in October 2015, summary judgment motions on behalf of all parties are pending, and a bench trial is set for April 2016.

Gas Supply Clause

LG&E's natural gas rates contain a gas supply clause, whereby the expected cost of natural gas supply and variances between actual and expected costs from prior periods are adjusted quarterly in LG&E's rates, subject to approval by the KPSC.  The gas supply clause includes a separate natural gas procurement incentive mechanism, a performance-based rate, which allows LG&E's rates to be adjusted annually to share variances between actual costs and market indices between the shareholders and the customers during each performance-based rate year (12 months ending October 31).  The regulatory assets or liabilities represent the total amounts that have been under- or over-recovered due to timing or adjustments to the mechanisms and are recovered within 18 months.

Fuel Adjustment Clauses

LG&E's and KU's retail electric rates contain a fuel adjustment clause, whereby variances in the cost of fuel for electric generation, including transportation costs, from the costs embedded in base rates are adjusted in LG&E's and KU's rates.  The KPSC requires public hearings at six-month intervals to examine past fuel adjustments and at two-year intervals to review past operations of the fuel clause and, to the extent appropriate, reestablish the fuel charge included in base rates.

KU also employs a levelized fuel factor mechanism for Virginia customers using an average fuel cost factor based primarily on projected fuel costs.  The Virginia levelized fuel factor allows fuel recovery based on projected fuel costs for the coming year plus an adjustment for any under- or over-recovery of fuel expenses from the prior year.  The regulatory assets or liabilities represent the amounts that have been under- or over-recovered due to timing or adjustments to the mechanism and are typically recovered within 12 months.

Interest Rate Swaps

(PPL, LKE and LG&E)

Because realized amounts associated with LG&E's interest rate swaps, including a terminated swap contract, are recoverable through rates based on an order from the KPSC, LG&E's unrealized gains and losses are recorded as a regulatory asset or liability until they are realized as interest expense.  Interest expense from existing swaps is realized and recovered over the terms of the associated debt, which matures through 2033.  Amortization of the gain/loss related to the terminated swap contract is recovered through 2035, as approved by the KPSC.

(LKE and LG&E)Other

In addition to the third quarter of 2010, LG&E recorded a pre-tax gain to reverse previously recorded losses of $21 million and $9 million to reflectabove matters, from time-to-time in the reclassificationordinary course of its ineffective swapsbusiness Talen Energy may be subject to other legal proceedings, claims and terminated swap to regulatory assets based on an order fromlitigation. While the KPSCoutcome of these legal proceedings, claims and litigation is uncertain, the likely results are not expected, either individually or in the 2010 rate case wherebyaggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the costeffect could be material to Talen Energy's results of LG&E's terminated swap was allowed to be recoveredoperations in base rates.  Previously, gains and losses on interest rate swaps designated as effective cash flow hedges were recorded within OCI and common equity.  The gains and losses on the ineffective portion of interest rate swaps designated as cash flow hedges were recorded to earnings monthly, as was the entire change in the market value of the ineffective swaps.
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(PPL, LKE, LG&E and KU)any interim reporting period.

In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013.  These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties.  LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities.  The gains and losses will be recognized in "Interest Expense" on the Statements of Income over the life of the underlying debt.  See Note 19 for additional information related to the forward-starting interest rate swaps.

AROs

As discussed in Note 1, the accretion and depreciation related to LG&E's and KU's AROs are offset with a regulatory credit on the income statement, such that there is no earnings impact.  When an asset with an ARO is retired, the related ARO regulatory asset created by the regulatory credit is offset against the associated regulatory liability, PP&E and ARO liability.

Power Purchase Agreement - OVEC

As a result of purchase accounting associated with PPL's acquisition of LKE, the fair values of the OVEC power purchase agreement were recorded on the balance sheets of LKE, LG&E and KU with offsets to regulatory liabilities.  The regulatory liabilities are being amortized using the units-of-production method until March 2026, the expiration date of the agreement at the date of the acquisition.

Regulatory Liability associated with Net Deferred Tax Assets

LG&E's and KU's regulatory liabilities associated with net deferred tax assets represent the future revenue impact from the reversal of deferred income taxes required primarily for unamortized investment tax credits.  These regulatory liabilities are recognized when the offsetting deferred tax assets are recognized.  For general-purpose financial reporting, these regulatory liabilities and the deferred tax assets are not offset; rather, each is displayed separately.

Regulatory MattersCredit Arrangements and Short-term Debt

Kentucky ActivitiesTalen Energy maintains credit arrangements to enhance liquidity and provide credit support. For reporting purposes, on a consolidated basis, the credit arrangements of Talen Energy Supply and its subsidiaries also apply to Talen Energy Corporation.
Revolving Credit Facilities

(PPL, LKE, LG&EThe following secured revolving credit facilities were in place at December 31, 2015:         
 
Expiration
Date
 Capacity Borrowed (c) Letters of
Credit
Issued		 
Unused
Capacity
 
Talen Energy Supply RCF (a)June 2020 $1,850
 $500
 $163
 $1,187
 
New MACH Gen RCF (b)July 2021 160
 108
 31
 21
 
      Total Credit Facilities  $2,010
 $608
 $194
 $1,208
 

(a)The facility is syndicated and provides capacity available for short-term borrowings and up to $925 million of letters of credit. The facility requires Talen Energy Supply to maintain a senior secured net debt to adjusted EBITDA ratio (as defined in the agreement) of less than or equal to 4.50 to 1.00 as of the last day of any fiscal quarter. Talen Energy Supply pays customary fees on the facility and borrowings bear interest at its option at either a defined base rate or LIBOR-based rates, in each case plus an applicable margin. The weighted average interest rate on outstanding borrowings at December 31, 2015 was 2.67%.
(b)
The facility provides capacity available for short-term borrowings and up to $120 million of letters of credit. New MACH Gen pays customary fees on the facility and borrowings bear interest at 12-month LIBOR, plus an applicable margin. The weighted average interest rate on outstanding borrowings at December 31, 2015 was 5.04%.
(c)The amounts borrowed are recorded as "Short-term debt" on the Balance Sheet.

The Talen Energy Supply RCF was entered into on June 1, 2015 in connection with the completion of the spinoff transaction and KU)replaced Talen Energy Supply's previously existing unsecured syndicated credit facility. Any outstanding principal amounts under the old facility were repaid prior to the termination of the old facility and outstanding letters of credit were transferred to the Talen Energy Supply RCF. The facility is secured by liens on a majority of Talen Energy Supply's assets and is guaranteed by certain Talen Energy Supply subsidiaries, which guarantees are in turn secured by liens on assets of such subsidiaries with an aggregate carrying value of $7 billion at December 31, 2015. The facility provides the option to raise incremental credit facilities, refinance the loans with debt incurred outside the facility and extend the maturity date of the revolving credit commitments and loans and, if applicable, term loans, subject to certain limitations.

Rate Case ProceedingsThe Talen Energy Supply letter of credit facility and uncommitted credit facilities that existed at December 31, 2014 either expired or matured during the first quarter of 2015. Any previously issued letters of credit under these facilities were either terminated or reissued under the then-outstanding unsecured syndicated credit facility and upon closing of the spinoff were reissued under the Talen Energy Supply RCF described above. During the year ended December 31, 2015, Talen Energy wrote-off $12 million of unamortized fees to "Interest expense" on the Statements of Income as a result of the termination of the prior unsecured syndicated credit facility.

The New MACH Gen RCF is a component of the $642 million First Lien Credit and Guaranty Agreement, which was outstanding when Talen Energy acquired MACH Gen in November 2015. The First Lien Credit and Guaranty Agreement also contains a Term Loan B as described in "Long-term Debt" below. Obligations under the First Lien Credit and Guaranty Agreement are guaranteed by each of New MACH Gen's subsidiaries and are secured by a first priority security interest, subject to possible shared first lien status with certain permitted hedge and power sale agreements, in all of the assets of New MACH Gen and each guarantor, including the equity interests in New MACH Gen and each guarantor, which assets collectively have an aggregate carrying value of approximately $1 billion at December 31, 2015. Talen Energy is not a guarantor or obligor of borrowings under the First Lien Credit and Guaranty Agreement.

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Other Facilities

Talen Energy Supply maintains a $500 million agreement expiring June 2017 that provides Talen Energy Supply the ability to request up to $500 million of committed unsecured letter of credit capacity at fees to be agreed upon at the time of each request, based on certain market conditions.  At December 31, 2015, Talen Energy Supply had not requested any capacity for the issuance of letters of credit under this arrangement.

In December 2015, Talen Energy Supply and Talen Energy Marketing entered into the Amended Secured Energy Marketing and Trading Facility Agreement (Amended STF Agreement) to amend the $800 million Secured Energy Marketing and Trading Facility Common Agreement, dated as of November 1, 2010. The Amended STF Agreement increased the facility capacity to $1.3 billion. The facility allows Talen Energy Supply to receive credit to satisfy collateral posting obligations related to Talen Energy's energy marketing and trading activities with counterparties participating in the facility. Prior to the Talen Energy spinoff transactions, Montour, LLC and Brunner Island, LLC had guaranteed certain of Talen Energy Marketing's obligations and had granted mortgage liens on their respective generating facilities to secure such guarantees. Brunner Island and Montour have since been released as parties. Obligations under the Amended STF Agreement are secured by the same collateral that secures the Talen Energy Supply RCF described above. The facility is for a five-year term that is subject to an automatic one-year extension each year until termination under the provisions of the Amended STF Agreement. The initial term expires in December 2020. There were $54 million of secured obligations outstanding under this facility at December 31, 2015.

Long-term Debt

The following long-term debt was outstanding at December 31:
 2015 2014
 Weighted-Average Rate Maturities    
Senior Unsecured Notes5.41% 2016-2038 $3,713
 $2,193
Senior Secured Notes8.86% 2025 41
 45
Term Loan B6.21% 2022 474
 —
Total Long-term Debt Before Adjustments    4,228
 2,238
        
Fair market value adjustments    (23) (19)
Unamortized premium and (discount), net    (2) (1)
Total Long-term Debt    4,203
 2,218
Less current portion of Long-term Debt, including fair market value adjustment    399
 535
Total Long-term Debt, noncurrent    $3,804
 $1,683

The aggregate maturities of long-term debt are as follows:

2016 2017 2018 2019 2020 Thereafter Total
$396
 $5
 $424
 $1,244
 $179
 $1,980
 $4,228

Long-term Debt Activity

In May 2015, Talen Energy Supply issued $600 million of 6.50% Senior Unsecured Notes due 2025. Talen Energy Supply received proceeds of $591 million, net of underwriting fees, which were used for repayment of short-term debt. The notes may be redeemed at Talen Energy Supply's option, in whole at any time or in part from time to time, prior to June 2012, LG&E1, 2020 at a price equal to 100% of their principal amount plus a make-whole premium and KU filed requestson or after June 1, 2020 at specified redemption prices. In addition, on or prior to June 1, 2018, up to 35% of the notes may be redeemed by Talen Energy Supply with proceeds from certain equity offerings at a price equal to 106.5% of the principal amount.

In June 2015, Talen Energy Supply assumed $1.25 billion of RJS Power Holdings LLC's 5.125% Senior Notes due 2019 as a result of the merger of RJS Power Holdings LLC into Talen Energy Supply, by which Talen Energy Supply became the obligor of these notes. In connection with this event and pursuant to the terms of the indenture governing the notes, the coupon on the notes was reduced to 4.625% in July 2015.


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In September 2015, Talen Energy Supply completed a remarketing of $231 million of Exempt Facilities Revenue Refunding Bonds, Series 2009A due 2038, Series 2009B due 2038, and Series 2009C due 2037 that were issued by PEDFA on behalf of Talen Energy Supply in 2009. All series bore interest at a fixed rate of 3.0% prior to the remarketing. The Series 2009A Bonds, with a principal amount of $100 million, were remarketed at a fixed coupon of 6.40% to maturity. The Series 2009B Bonds and Series 2009C Bonds, with an aggregate principal amount of $131 million, were remarketed at a fixed rate of 5.00% for five years, at which time they will be subject to mandatory repurchase and optional remarketing. This transaction is excluded from the Statement of Cash Flows as a non-cash transaction.

In October 2015, Talen Energy Supply's $300 million of 5.70% REset Put Securities due 2035 (REPS) were subject to mandatory tender to the remarketing dealer. However, the remarketing dealer and Talen Energy Supply mutually agreed to terminate the remarketing dealer's right to remarket the REPS and, in accordance with the KPSCterms of the REPS, Talen Energy Supply repurchased the REPS at par. The total aggregate consideration paid to repurchase the REPS was $434 million, which included $300 million of principal and $134 million of remarketing option value paid to the remarketing dealer. The termination payment to the remarketing dealer was recorded to "Other Income (Expense) - net" on the 2015 Statement of Income and is reflected in "Cash from operating activities" on the 2015 Statement of Cash Flows.

Following the MACH Gen acquisition in November 2015, $475 million of New MACH Gen Term Loan B debt secured under the First Lien Credit and Guaranty Agreement, which is described above, remained outstanding. The Term Loan B provides customary annual amortization paid quarterly and may also be repaid, in whole or in part, beginning in the third quarter of 2016 without any make-whole premium. See "Credit Arrangements and Short-term Debt - Revolving Credit Facilities" above for increasesinformation regarding guarantees of and security interests with respect to the First Lien Credit and Guaranty Agreement.

In December 2015, Talen Energy Supply announced an "exchange offer" for its 6.5% Senior Unsecured Notes due 2025 that were issued in annual base electric ratesMay 2015. Pursuant to the terms of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas ratesthe notes, Talen Energy Supply offered to exchange all of approximately $17 million at LG&E.the outstanding notes for a like principal amount of its 6.5% Senior Notes due 2025 that, have been registered under the Securities Exchange Act of 1933, as amended. In November 2012, LG&E and KU alongJanuary 2016, the exchange offer was completed with all of the notes exchanged.

In connection with the sale of Talen Ironwood Holdings, LLC, in January 2016, a Talen Ironwood Holdings, LLC subsidiary completed the redemption of $41 million of its 8.857% Senior Secured Notes due 2025 prior to the closing of the sale transaction, which occurred in February 2016. The redemption included the payment of a make whole premium of $14 million, which will be recorded as a component of the expected gain on sale in "Operating Income" on the Statement of Income in 2016. See Note 6 for additional information on the sale of Talen Ironwood Holdings, LLC.

Preferred Stock of Talen Energy Corporation

Talen Energy Corporation is authorized under its Amended and Restated Certificate of Incorporation to issue up to 100 million shares of preferred stock. No shares of preferred stock were issued or outstanding at December 31, 2015.

Legal Separateness

The subsidiaries of Talen Energy Corporation are separate legal entities. Talen Energy Corporation's subsidiaries are not liable for the debts of Talen Energy Corporation. Accordingly, creditors of Talen Energy Corporation may not satisfy their debts from the assets of Talen Energy Corporation's subsidiaries absent a specific contractual undertaking by a subsidiary to pay Talen Energy Corporation's creditors or as required by applicable law or regulation. Similarly, Talen Energy Corporation is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of Talen Energy Corporation's subsidiaries may not satisfy their debts from the assets of Talen Energy Corporation or its other subsidiaries absent a specific contractual undertaking by Talen Energy Corporation or its other subsidiaries to pay the creditors or as required by applicable law or regulation.

Similarly, the subsidiaries of Talen Energy Supply are each separate legal entities. These subsidiaries are not liable for the debts of Talen Energy Supply. Accordingly, creditors of Talen Energy Supply may not satisfy their debts from the assets of their subsidiaries absent a specific contractual undertaking by a subsidiary to pay the creditors or as required by applicable law or regulation. Similarly, Talen Energy Supply is not liable for the debts of its subsidiaries, nor are the subsidiaries liable for the debts of one another. Accordingly, creditors of these subsidiaries may not satisfy their debts from the assets of Talen Energy Supply absent a specific contractual undertaking by that parent or other subsidiary to pay such creditors or as required by applicable law or regulation.


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As indicated above, certain debt agreements, including, but not limited to, the Talen Energy Supply RCF, the First Lien Credit and Guaranty Agreement and the Amended STF Agreement, include contractual undertakings by certain Talen Energy subsidiaries to guarantee the obligations of other Talen Energy entities arising under those agreements.

Distribution Related Restrictions for Talen Energy Corporation

Certain of Talen Energy's debt agreements include covenants that could effectively restrict the payment of distributions, loans or advances, either directly to Talen Energy Corporation or to Talen Energy Supply or one of its subsidiaries. At December 31, 2015, $3.3 billion of Talen Energy Corporation subsidiaries net assets were restricted for the purposes of transferring funds to Talen Energy Corporation in the form of distributions, loans or advances.

6.  Acquisitions, Development and Divestitures

Talen Energy from time to time evaluates opportunities for potential acquisitions, divestitures and development projects.  Development projects are periodically reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.  Any resulting transactions may impact future financial results.  

Acquisitions

MACH Gen

On November 2, 2015, Talen Energy completed the acquisition of the membership interests of MACH Gen for $603 million in cash consideration (based on estimated working capital). The final cash purchase price, after post-closing adjustments, was $600 million. The purchase price was funded by a borrowing under the Talen Energy Supply RCF and cash on hand. The Term Loan B and revolving credit facility of New MACH Gen remain outstanding following the completion of the transaction. See Note 5 for additional information. MACH Gen's total generating capacity is 2,344 MW (summer rating).
The MACH Gen acquisition was accounted for as a business combination, with the identifiable tangible and intangible assets and liabilities of MACH Gen, recorded at their estimated fair values on the acquisition date. The acquisition is consistent with management's strategy of business growth, fuel type diversity and replacing the assets being divested as part of the FERC approval of the RJS Power acquisition. The following table summarizes the allocation of the purchase price to the fair values of the major classes of assets and liabilities of MACH Gen.
Current assets (a) $31
Intangible assets 3
PP&E 1,275
Short-term debt (103)
Current liabilities (28)
Long-term debt (470)
Deferred income taxes (108)
Total purchase price $600

(a)
Includes gross contractual amounts of accounts receivable acquired of $9 million, which approximates fair value.

The purchase price allocation is considered by Talen Energy's management to be provisional due to pending finalization of valuations and could change materially in subsequent periods. Any changes to the provisional purchase price allocation during the measurement period that result in material changes to the consolidated financial results will be adjusted prospectively. The measurement period can extend up to a year from the date of acquisition. The items pending finalization include, but are not limited to, the valuation of PP&E, certain other assets and liabilities and deferred income taxes.

Actual operating revenues and net income of MACH Gen, since the November 2, 2015 acquisition, included in Talen Energy's results for the year ended December 31, 2015 were:
 Operating Revenues Net Income (Loss)
 $28
 $(9)

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RJS Power

On June 1, 2015, substantially contemporaneous with the spinoff by PPL to form Talen Energy, RJS Power was contributed by the Riverstone Holders to become a subsidiary of Talen Energy Supply in exchange for 44,974,658 shares of Talen Energy Corporation common stock. See Notes 1 and 3 for additional information on the spinoff and acquisition. In accordance with business combination accounting guidance, Talen Energy treated the combination with RJS Power as an acquisition and Talen Energy Supply is considered the acquirer of RJS Power. Accordingly, Talen Energy applied acquisition accounting to the assets and liabilities of RJS Power whereby the purchase price was allocated to the underlying tangible and intangible assets and liabilities based on their respective fair values as of June 1, 2015, with the remainder allocated to goodwill.

The total consideration for the acquisition was deemed to be $902 million based on the fair value of the Talen Energy Corporation common stock issued for the acquisition using the June 1, 2015 closing "when-issued" market price.

The following table summarizes the allocation of the purchase price to the fair values of the major classes of assets and liabilities of RJS, all of which represent non-cash activity excluded from the Statement of Cash Flows for the year ended December 31, 2015. The purchase price allocation is considered by Talen Energy's management to be final as of December 31, 2015.

Current assets (a) $168
Assets of discontinued operations (b) 375
PP&E 1,777
Other intangibles 46
Short-term debt (36)
Current liabilities (224)
Liabilities of discontinued operations (5)
Long-term debt (1,244)
Deferred income taxes (266)
Other noncurrent liabilities (c) (82)
Net identifiable assets acquired 509
Goodwill (d) 393
Net assets acquired $902

(a)
Includes gross contractual amount of the accounts receivable acquired of $41 million, which approximates fair value.
(b)
See Note 14 for information on impairment charges recorded during 2015 related to the Sapphire plants initial classification as assets held for sale and discontinued operations. See Note 1 for additional information on the subsequent reclassification to assets held and used.
(c)
Includes $33 million of "out-of-the-money" coal contracts that will be amortized over the life of the contracts terms as the coal is consumed.
(d)
The allocation above is as of the acquisition date of June 1, 2015. As further discussed in Note 16, goodwill was fully impaired during 2015, which included the goodwill recognized in the acquisition of RJS Power.

Various purchase accounting valuation adjustments were made during the third and fourth quarters affecting certain current assets and liabilities, PP&E, other intangibles and related deferred income taxes resulting in a $5 million reduction in goodwill. The statement of income effect of these adjustments recorded during the measurement period was insignificant.

Goodwill recorded as a result of the acquisition primarily reflected synergies expected to be achieved related to the spinoff and acquisition. The goodwill is not deductible for income tax purposes and was assigned to the East segment. See Note 16 for additional information related to the impairment of goodwill.

Actual operating revenues and net income of RJS, since the June 1 acquisition, included in Talen Energy's results for the year ended December 31, 2015 were:
 Operating Revenues Net Income (Loss) (a)
 $528
 $(74)

(a)Includes certain asset impairments and excludes the impact of the goodwill impairment recorded in 2015 subsequent to the acquisition. See Notes 14 and 16 for information on the impairments recorded.


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Pro Forma Information for RJS Power and MACH Gen Acquisitions

Pro forma information (unaudited) for Talen Energy for the year ended December 31, as if both the RJS Power and MACH Gen acquisitions had occurred January 1, 2014, is as follows:

  Operating Revenues  Income (Loss) After Tax from Continuing Operations
2015:    
Pro forma $5,109
 $(396)
Basic and diluted earnings per share (for Talen Energy Corporation)   (3.08)
2014:    
Pro forma 6,031
 345
Basic and diluted earnings per share (for Talen Energy Corporation)   2.68

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the acquisitions taken place on the date indicated, or the future consolidated results of operations of Talen Energy. The pro forma financial information presented above has been derived from the historical consolidated financial statements of Talen Energy and MACH Gen and from the historical consolidated and combined financial statements of RJS Power.

The pro forma financial information presented above includes adjustments for (1) alignment of accounting policies, (2) incremental depreciation and amortization expense related to fair value adjustments to PP&E and identifiable intangible assets and liabilities, (3) incremental interest expense for outstanding borrowings to reflect the terms of the Talen Energy Supply RCF related to the RJS acquisition, (4) nonrecurring items (discussed below), (5) the tax effect of the above adjustments, and (6) the issuance of Talen Energy Corporation common stock in connection with the spinoff from PPL and the acquisition of RJS Power. The pro forma financial information presented includes the impact of impairments recorded during the third and fourth quarters of 2015. See Notes 14 and 16 for information on the impairments recorded.

Nonrecurring acquisition, integration and other costs directly related to the acquisitions of $20 million were incurred during 2015 and recorded in "Operation and maintenance" on the Statements of Income. Adjustments were made in the calculation of pro forma amounts to remove the effect of these nonrecurring items and related income taxes. The pro forma financial information does not include adjustments for potential future cost savings for either acquisition.

Divestitures

Talen Renewable Energy

In November 2015, Talen Energy completed the sale of Talen Renewable Energy for $116 million in cash and recorded a pre-tax gain on the sale of $10 million in the East segment, which is reflected in "Operation and maintenance" on the Statement of Income.

Announced Divestitures

Ironwood, Holtwood, Lake Wallenpaupack and C.P. Crane Power Plants

In October 2015, Holtwood, LLC, a wholly owned, indirect subsidiary of Talen Energy, entered into an agreement to sell the Holtwood and Lake Wallenpaupack hydroelectric facilities in Pennsylvania for a purchase price of $860 million, subject to customary purchase price adjustments. The facilities have a combined summer rating operating capacity of 308 MW. The transaction is expected to close in March 2016, subject to customary closing conditions.

In October 2015, Talen Generation entered into an agreement to sell Talen Ironwood Holdings, LLC, which through its subsidiaries owns and operates the Ironwood natural gas combined-cycle plant in Pennsylvania, for a purchase price of $657 million, subject to customary purchase price adjustments. In connection with the sale, in January 2016, Talen Energy repaid $41 million of indebtedness, plus a customary debt make-whole premium. The Ironwood unit has a summer rating operating capacity of 660 MW. The sale transaction closed in February 2016, with an estimated gain, net of transaction costs including

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the make-whole premium on the debt, of $159 million, which will be recorded to "Operating Income" on the Statement of Income in 2016. Proceeds from the sale of Ironwood were used to repay the majority of Talen Energy's short-term debt.

In October 2015, Raven Power Marketing LLC, a wholly owned, indirect subsidiary of Talen Energy, entered into an agreement to sell C.P. Crane LLC, which owns and operates the C.P. Crane coal-fired power plant in Maryland. The C.P. Crane plant has a summer rating operating capacity of 402 MW. The transaction closed in February 2016. The transaction is not expected to have a significant impact on Talen Energy's financial condition or results of operations. See Notes 14 and 16 for information on impairments recorded in 2015 for this plant.

The sales are part of the requirement to divest certain PJM assets to satisfy a December 2014 FERC order approving the combination with RJS Power. See Note 1 for information on the FERC order.

At December 31, 2015, the major component of assets held for sale related to the sale of these businesses was primarily $936 million of PP&E which was included in the East segment. Talen Ironwood Holdings, LLC is considered an individually significant component whose pretax income (loss) attributable to Talen Energy for 2015, 2014, and 2013 was $73 million, $67 million, and $(22) million.

Discontinued Operations

Talen Montana Hydro Sale

In November 2014, Talen Montana completed the sale to NorthWestern Corporation of 633 MW of hydroelectric generating facilities located in Montana for approximately $900 million in cash.  The sale included 11 hydroelectric power facilities and related assets.

Following are the components of discontinued operations in the Statement of Income for the years ended December 31.    
  2014 2013
Operating revenues $117
 $139
Gain on the sale (pre-tax) 306
 —
Interest expense (a) 9
 12
Income (loss) before income taxes 332
 49
Income (Loss) from Discontinued Operations (net of income taxes) 223
 32

(a)Represents allocated interest expense based upon the discontinued operations share of the net assets of Talen Energy.  

Other

To facilitate the sale of the Montana hydroelectric generating facilities discussed above, Talen Montana terminated, in December 2013, its operating lease arrangement related to partial interests in Units 1, 2 and 3 of the Colstrip coal-fired generating facility and acquired those interests, collectively, for $271 million. At lease termination, the existing lease-related assets on the balance sheet consisting primarily of prepaid rent and leasehold improvements were written off and the acquired Colstrip assets were recorded at fair value as of the acquisition date. Talen Energy recorded a charge of $697 million ($413 million after-tax) for the termination of the lease included in "Loss on lease termination" on the 2013 Statements of Income. The $271 million payment is reflected in "Cash Flows from Operating Activities" on the 2013 Statement of Cash Flow.

Development

Bell Bend COLA

In 2008, a Talen Energy subsidiary, Bell Bend, LLC (Bell Bend) submitted a COLA to the NRC for the proposed Bell Bend nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna plant.

Also in 2008, Bell Bend submitted Parts I and II of an application for a federal loan guarantee for Bell Bend to the DOE. In February 2014, the DOE announced the first loan guarantee for a nuclear project in Georgia. Although eight of the ten applicants that submitted Part II applications remain active in the DOE program, the DOE has stated that the $18.5 billion currently appropriated to support new nuclear projects would not likely be enough for more than three projects. Bell Bend submits quarterly application updates for Bell Bend to the DOE to remain active in the loan guarantee application process.

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The NRC continues to review the COLA. Bell Bend does not expect to complete the COLA review process with the NRC prior to 2018. Bell Bend has made no decision to proceed with construction and expects that such decision will not be made for several years given the anticipated lengthy NRC license approval process. Additionally, Bell Bend does not expect to proceed with construction absent favorable economics, a joint arrangement with other interested parties and a federal loan guarantee or other acceptable financing. Bell Bend is currently authorized by Talen Energy Corporation's Board of Directors to spend up to $256 million on the COLA and other permitting costs necessary for construction. At December 31, 2015 and 2014, $201 million and $188 million of costs, which includes capitalized interest, associated with the licensing application were capitalized and are included on the Balance Sheets in noncurrent "Other intangibles." Talen Energy continues to support the Bell Bend licensing project with a near term focus on obtaining the final environmental impact statement. Talen Energy placed the NRC safety review (which supports issuance of their final safety evaluation report, the other key element of the COLA) on hold in 2014, due to a lack of progress by the reactor vendor with respect to its NRC design certification process, which is a prerequisite to the COLA.

Brunner Island Co-firing Project

Talen Energy is in the process of making modifications to its Brunner Island coal-fired generating facility to be able to co-fire using natural gas to better position the plant for low gas price environments. Construction is under way and is expected to be completed by the end of 2016. The project is expected to cost $118 million. At December 31, 2015 and 2014, $23 million and $5 million of costs, which include capitalized interest, associated with the project were capitalized and are included in "Construction work in progress" on the Balance Sheets.

7. Leases

Talen Energy and its subsidiaries have entered into various agreements for the lease of office space, vehicles, land, gas storage and other equipment. At December 31, 2015, Talen Energy's most significant lease, which expires in 2018, relates to its corporate headquarters.

Rent expense for the years ended December 31 for operating leases was as follows:
 2015 2014 2013
 $14
 $29
 $55

Total future minimum rental payments for all operating leases are estimated to be:
2016 2017 2018 2019 2020 Thereafter Total
$19
 $18
 $8
 $5
 $5
 $26
 $81

8.  Stock-Based Compensation

Stock Incentive Plan

Talen Energy Corporation grants share-based compensation to eligible participants under the Talen Energy Stock Incentive Plan (SIP). Under the SIP, restricted shares of Talen Energy Corporation stock, restricted stock units, performance units, stock options and stock appreciation rights may be granted to officers, directors and other key employees. Additionally, Talen Energy Corporation will match shares of its common stock purchased by certain employees on the open market from June 1, 2015 through March 31, 2018 with grants of restricted stock units, subject to certain restrictions (Matching Grants). Awards under the SIP are made by the Compensation, Governance and Nominating Committee (CGNC) of the Talen Energy Corporation Board of Directors or its delegate.

The total number of shares which may be issued under the plan is 5,630,000 and the maximum number of shares for which stock options may be granted is 2,000,000. Shares delivered under the SIP may be in the form of authorized and unissued Talen Energy Corporation common stock or common stock held in treasury by Talen Energy Corporation.

Restricted Stock Units

Restricted stock units are awards based on the fair value of a share of Talen Energy Corporation common stock on the date of grant. Actual Talen Energy Corporation common shares will be issued upon completion of a vesting period of three years,

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aside from Matching Grants that generally vest two years from the date of grant. Substantially all restricted stock unit awards are expected to vest.

The fair value of restricted stock units granted is recognized as compensation expense on a straight-line basis over the service period. Restricted stock units are subject to forfeiture or accelerated payout under the pertinent award agreement provisions for termination, disability and death of employees. Restricted stock units vest fully, in certain situations, as defined by in the applicable award agreement. The total restricted stock units granted, nonvested and outstanding through December 31, 2015 was 265,849 and the weighted-average grant date fair value per share was $18.74.

Stock Options

Stock options have been granted with an option exercise price per share not less than the fair value of Talen Energy Corporation's common stock on the date of grant. Options become exercisable in equal installments over a three-year service period beginning one year after the date of grant, assuming the individual is still employed by Talen Energy or a subsidiary. The CGNC has discretion to accelerate the exercisability of the options. All options expire no later than ten years from the grant date. The options become exercisable immediately in certain situations, as defined by the pertinent award agreement. The fair value of options granted is recognized as compensation expense on a straight-line basis over the service period. Substantially all stock option awards are expected to vest. The total stock options granted, nonvested and outstanding through December 31, 2015 was 991,101 and the grant date fair value per share was $4.91. The weighted-average exercise price per share is $19.00 and the weighted-average remaining contractual term is 9.4 years. The stock options outstanding at December 31, 2015 are currently out of the money.
The fair value of each option granted is estimated using a Black-Scholes option-pricing model. Talen Energy uses a risk-free interest rate, expected option life and expected volatility to value its stock options. Talen Energy Corporation does not currently expect to pay dividends, therefore a dividend yield assumption is not used to value stock options. The risk-free interest rate reflects the yield for a U.S. Treasury Strip available on the date of grant with constant rate maturity approximating the option's expected life. Expected life was calculated using the simplified method described in SEC Staff Accounting Bulletin (SAB) 107/110 (updated by SAB 110). Expected volatility is derived from the historical volatility of a peer group selected by management as Talen Energy Corporation's common stock does not have a trading history.

The assumptions used in the model were:
Risk-free interest rate2.05%
Expected option life6.00 years
Expected stock volatility21.55%

Performance Units

Performance units represent a target number of shares of Talen Energy Corporation's common stock that the recipient would receive upon Talen Energy Corporation's attainment of an applicable performance goal. For awards granted in 2015, Talen Energy Corporation uses TSR, which is determined based on TSR during a three-year performance period. At the end of the performance period, payout is determined by comparing Talen Energy Corporation's TSR to the TSR of peer group companies that Talen Energy Corporation has selected. Awards are payable on a graduated basis, based on thresholds that measure Talen Energy Corporation's performance relative to the peer group companies, on which each years' awards are measured. Awards can be paid up to 200% of the target award or forfeited with no payout if performance is below a minimum established performance threshold. Under the pertinent award agreement provisions, performance units are subject to forfeiture upon termination of employment except for in the event of a disability or death of an employee, in which case the total performance units remain outstanding and are eligible for vesting through the conclusion of the performance period. The fair value of performance units is recognized as compensation expense on a straight-line basis over the three-year performance period. Performance units vest on a pro rata basis, in certain situations, as defined by the applicable award agreement.

The fair value of performance units granted was estimated using a Monte Carlo pricing model that values market based performance conditions such as TSR. The model assumed an expected stock volatility of 31.8% that was based on the historical volatility based on daily stock price changes of peer group companies.

The total performance units granted, nonvested and outstanding through December 31, 2015 was 158,900 and the weighted-average grant date fair value was $21.17 per share.


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Directors Deferred Compensation Plan

Under the Talen Energy Corporation Directors Deferred Compensation Plan, or DDCP, stock units are granted to eligible directors of Talen Energy Corporation in connection with their retainers for service on Talen Energy Corporation’s board of directors and its committees. Stock units are based on the fair market value of a share of Talen Energy Corporation’s common stock on the date of grant. The total number of stock units granted under the DDCP through December 31, 2015 was 34,967 and the weighted average grant date fair value was $13.23 per share.

Compensation Expense

The year ended December 31, 2015 includes an insignificant amount of compensation expense for Talen Energy Corporation restricted stock units, performance units and stock options accounted for as equity awards.

The year ended December 31, 2014 includes compensation expense of $33 million and the associated income tax benefit of $14 million for restricted stock, restricted stock units, performance units and stock options accounted for as equity awards from PPL, which included an allocation of PPL Services' expense.

The year ended December 31, 2013 includes compensation expense of $27 million and the associated income tax benefit of $11 million for restricted stock, restricted stock units, performance units and stock options accounted for as equity awards from PPL, which included an allocation of PPL Services' expense.
At December 31, 2015, unrecognized compensation expense and the weighted-average period for recognition related to nonvested restricted stock units, performance units and stock option awards from Talen Energy was $11 million and 2.4 years.
Prior to the spinoff, restricted shares of PPL common stock and related restricted stock units, performance units and stock options were granted to officers and other key employees of Talen Energy. At December 31, 2014, these employees of Talen Energy had 1,457,900 of unvested shares of restricted stock and restricted stock units, 291,492 of performance units and 2,745,016 of outstanding stock options issued by PPL. The vesting of these awards was accelerated in 2015 in connection with the spinoff from PPL. See Note 1 for information on the recording of expense related to this acceleration and additional information on the spinoff from PPL. For the year ended December 31, 2015, compensation expense for these awards, excluding the acceleration, but including an allocation of PPL Services' compensation expense for similar awards, was $18 million.

9.  Retirement and Postemployment Benefits

Prior to the June 1, 2015 spinoff, the majority of Talen Energy Supply's employees were eligible for pension benefits under a PPL non-contributory defined benefit pension plan, with benefits based on length of service and either career average pay or final average pay, as defined by the plan. Prior to the June 1, 2015 spinoff, this plan was closed to all newly hired employees. Newly hired employees were eligible to participate in a PPL 401(k) savings plan with enhanced employer contributions. Talen Energy was allocated costs of the PPL pension plan based on its employees' participation in the plan. Employees who participated in this PPL pension plan who became employees of Talen Energy Supply transferred into a newly created pension plan sponsored by Talen Energy Supply, which provides benefits similar to that of the PPL pension plan.

Prior to the June 1, 2015 spinoff, the majority of Talen Energy Supply's employees were also eligible for certain health care and life insurance benefits upon retirement through the PPL other postretirement benefit plans, which prior to June 1, 2015, were closed to all newly hired employees. Talen Energy Supply was allocated costs of the PPL plans based on its employees' participation in the plans. Employees who participated in the health care and life insurance plans and who became employees of Talen Energy Supply transferred into the newly created Talen Energy other postretirement benefit plans sponsored by Talen Energy Supply, which provide benefits similar to those of the PPL other postretirement benefit plans.

A remeasurement of the assets and the obligations for the PPL pension and other postretirement benefit plans was performed as of May 31, 2015 in order to separate the assets and obligations of the PPL plans attributable to Talen Energy, as required by the spinoff agreements. The Talen Energy pension plan assumed from PPL the pension benefit obligations for active plan participants who became employees of Talen Energy in connection with the spinoff and for individuals who terminated employment from Talen Energy Supply on or after July 1, 2000. A portion of the PPL pension plan assets were also allocated to the new Talen Energy pension plan. The asset allocation was based on the rules prescribed by ERISA (Employee Retirement Income Security Act) for allocating assets in connection with a pension plan spinoff. The Talen Energy other postretirement benefit plans assumed the other postretirement benefit obligations from PPL for active plan participants who became

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employees of Talen Energy in connection with the spinoff. PPL retained obligations attributable to existing retirees as of the date of the spinoff. A portion of the PPL other postretirement benefit plan assets, which were held in VEBA trusts and a 401(h) account, were also allocated to the new Talen Energy other postretirement benefit plans. The asset allocation was determined separately for each funding vehicle based on the ratio of the accumulated postretirement benefit obligation (APBO) assumed by Talen Energy to the total APBO attributed to each funding vehicle. As a result of the above, the net funded status of the new Talen Energy pension and other postretirement benefit plans at June 1, 2015 was a liability of $257 million.

The majority of Talen Montana's employees are eligible for pension benefits under a cash balance plan. Effective January 1, 2012, that plan was closed to all newly hired salaried employees. Effective September 1, 2014, that plan was closed to all newly hired bargaining unit employees. Newly hired employees are eligible to participate in a 401(k) savings plan with enhanced employer contributions. The majority of Talen Montana's employees are also eligible for certain health care and life insurance benefits upon retirement, under a retiree health plan sponsored by Talen Montana, which is now closed to newly hired employees. There were no changes to the pension and other postretirement benefit plans for employees of Talen Montana as a result of the spinoff transaction. However, PPL retained the liability for other postretirement benefits attributable to existing retirees of Talen Montana as of the date of the spinoff.

Employees of certain of Talen Energy's mechanical contracting companies are eligible for benefits under multiemployer plans sponsored by various unions.

The following table provides the components of net periodic defined benefit costs for Talen Energy pension and other postretirement plans for the years ended December 31, for which the 2015 periods include seven months of costs under the newly formed Talen Energy plans and a full year of Talen Montana plans.
 Pension Benefits Other Postretirement Benefits
 2015
2014
2013 2015 2014 2013
Net periodic defined benefit costs (credits):           
Service cost$31
 $5
 $7
 $2
 $—
 $1
Interest cost46
 9
 8
 2
 1
 —
Expected return on plan assets(60) (11) (10) (3) —
 —
Amortization of:           
Actuarial (gain) loss16
 2
 3
 —
 —
 —
Curtailment charges (credits)—
 —
 —
 —
 (1) —
Net periodic defined benefit costs (credits)$33

$5

$8

$1

$—

$1
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
Other changes in plan assets and benefit obligations recognized in OCI:           
Curtailments$—
 $—
 $—
 $—
 $1
 $—
Net (gain) loss54
 26
 (15) —
 (1) (1)
Prior service cost (credit)3
 —
 —
 —
 —
 (3)
Amortization of:           
Actuarial gain (loss)(16) (2) (3) —
 —
 —
Prior service credit (cost)—
 —
 —
 1
 —
 —
Total recognized in OCI41
 24
 (18) 1
 —
 (4)
Total recognized in net periodic defined benefit costs and OCI$74
 $29
 $(10) $2
 $—
 $(3)

Actuarial loss of $20 million related to these plans is expected to be amortized from AOCI into net periodic defined benefit costs in 2016.

The following net periodic defined benefit costs (credits) were charged to operating expense, excluding amounts charged to construction and other non-expense accounts.

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 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
 $48
 $39
 $45
 $2
 $3
 $6

In the table above, amounts include costs for the specific plans sponsored by Talen Energy and its subsidiaries and the following allocated costs of the PPL pension and other postretirement benefit plans prior to the spinoff, based on Talen Energy Supply's participation in those plans, which management believes were reasonable at the time:
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
 $16
 $34
 $38
 $—
 $3
 $5

At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors adopted the mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables) for all applicable defined benefit pension and other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors also selected the IRS BB 2-Dimensional mortality improvement scale on a generational basis for all applicable defined benefit pension and other postretirement benefit plans. These mortality assumptions reflect the recognition of both improved life expectancies and the expectation of continuing improvements in life expectancies.

The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2015 2014
Discount rate4.65% 4.28% 4.60% 3.81%
Rate of compensation increase3.98% 4.03% 3.98% 4.03%

The following weighted-average assumptions were used to determine the net periodic defined benefit costs for Talen Energy's plans for the years ended December 31.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
Discount rate4.41% 5.18% 4.25% 4.27% 4.51% 3.77%
Rate of compensation increase3.99% 3.94% 3.95% 3.99% 3.94% 3.95%
Expected return on plan assets (a)7.00% 7.00% 7.00% 6.37% N/A
 N/A
(a)The expected long-term rates of return for pension and other postretirement benefits are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
The following table provides the assumed health care cost trend rates for the years ended December 31.
 2015 2014 2013
Health care cost trend rate assumed for next year     
obligations6.80% 7.20% 7.60%
costs7.20% 7.60% 8.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)     
obligations5.00% 5.00% 5.00%
costs5.00% 5.00% 5.50%
Year that the rate reaches the ultimate trend rate     
obligations2020
 2020
 2020
costs2020
 2020
 2019

A one percentage point change in the assumed health care costs trend rate assumption would have been insignificant to the other postretirement benefit plans in 2015.

105

The funded status of Talen Energy's plans at December 31 was as follows:
 Pension Benefits Other Postretirement Benefits
 2015 2014 2015 2014
Change in Benefit Obligation       
Benefit obligation, beginning of period$210
 $163
 $10
 $12
Transfer of benefit obligation at spinoff (a)1,416
 —
 80
 —
Service cost31
 5
 2
 —
Interest cost46
 9
 2
 1
Plan amendments3
 —
 —
 —
Actuarial (gain) loss(41) 38
 (4) (1)
Net Transfers in (out)—
 —
 (3) —
Curtailments—
 —
 —
 (1)
Gross benefits paid(51) (5) —
 (1)
Benefit obligation, end of period$1,614
 $210
 $87
 $10
        
Change in Plan Assets       
Plan assets at fair value, beginning of period$170
 $147
 $—
 $—
Transfer of plan assets at fair value at spinoff (a)1,159
 —
 80
 —
Actual return on plan assets(35) 22
 (2) —
Employer contributions32
 6
 1
 1
Gross benefits paid(52) (5) (1) (1)
Plan assets at fair value, end of period1,274
 170
 78
 —
Funded status end of period$(340) $(40) $(9) $(10)
        
Amounts recognized in the Balance Sheets consist of:       
Current Liability$—
 $—
 $—
 $(1)
Noncurrent liability(340) (40) (9) (9)
Net amount recognized, end of period$(340) $(40) $(9) $(10)
        
Amounts recognized in AOCI (pre-tax) consist of:       
Prior service cost (credit)$2
 $—
 $(5) $(4)
Net actuarial (gain) loss451
 59
 8
 —
Total$453
 $59
 $3
 $(4)
        
Total accumulated benefit obligation for defined benefit pension plans$1,500
 $210
 
 

(a)Values determined as of the spinoff date as discussed above.

Talen Energy's pension plans had projected and accumulated benefit obligations in excess of the fair value of plan assets at December 31, 2015 and 2014.

In addition to the plans it sponsors, Talen Energy Supply and its subsidiaries were allocated a portion of the funded status and costs of the defined benefit plans sponsored by PPL Services based on their participation in those plans prior to the spinoff, which management believes were reasonable at that time. The actuarially determined obligations of current active employees were used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to Talen Energy Supply resulted in liabilities at December 31, 2014 as follows:
Pension plans$259
Other postretirement benefit plans34

Talen Energy's mechanical contracting subsidiaries make contributions to over 60 multiemployer pension plans, based on the bargaining units from which labor is procured. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:


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Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.

If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

If Talen Energy's mechanical contracting subsidiaries choose to stop participating in some of their multiemployer plans, they may be required to pay those plans an amount based on the unfunded status of the plan, referred to as a withdrawal liability.

Talen Energy identified the Steamfitters Local Union No. 420 Pension Plan, EIN/Plan Number 23-2004424/001 as the plan to which the most significant contributions are made. Contributions to this plan by Talen Energy's mechanical contracting companies were $5 million for 2015, 2014 and 2013. At the date the financial statements were issued, the Form 5500 was not available for the plan year ending in 2015. Therefore, the following disclosures specific to this plan are being made based on the Form 5500s filed for the plan years ended December 31, 2014 and 2013. Talen Energy's mechanical contracting subsidiary H.T. Lyons was identified individually as a greater than 5% contributor on the Form 5500s. The plan had a Pension Protection Act zone status of red, without utilizing an extended amortization period, as of December 31, 2014 and 2013. In addition, the plan is subject to a rehabilitation plan and surcharges have been applied to participating employer contributions. The expiration date of the collective-bargaining agreement related to those employees participating in this plan is September 18, 2016. There were no other plans deemed individually significant based on a multifaceted assessment.

Talen Energy's mechanical contracting subsidiaries also participate in multiemployer other postretirement plans that provide for retiree life insurance and health benefits.

The table below details total contributions to all multiemployer pension and other postretirement plans, including the plan identified as significant above. The contribution amounts fluctuate each year based on the volume of work and type of projects undertaken from year to year.
 2015 2014 2013
Pension plans$34
 $40
 $36
Other postretirement benefit plans26
 33
 32
Total contributions$60
 $73
 $68

Plan Assets

At December 31, 2015, Talen Energy's pension plans are invested in the Talen Energy Retirement Plans Master Trust (the Master Trust) that also includes a 401(h) account that is restricted for certain other postretirement benefit obligations of Talen Energy. Prior to the spinoff from PPL, the pension plan assets were invested by PPL in a master trust maintained by PPL.

The investment strategy for the Master Trust is to achieve a risk-adjusted return on a mix of assets that, in combination with Talen Energy's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments, while also managing the duration of the assets to complement the duration of the liabilities. The Master Trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore has no significant concentration of risk.

The investment policy of the Master Trust outlines investment objectives and defines the responsibilities of the Retirement Plan Committee of Talen Energy Corporation, which is the named fiduciary, external investment managers, investment advisor and trustee and custodian. The investment policy is reviewed annually by Talen Energy Corporation's Board of Directors.

The Retirement Plan Committee created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios: growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return at a reasonable risk, including equity securities, certain debt securities and alternative investments. The immunizing portfolio consists of debt securities, generally with long durations, and derivative positions. The immunizing portfolio is designed to offset a portion of the change in the pension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of cash and cash equivalents.

Target asset allocation ranges have been developed for the Master Trust based on input from external consultants with a goal of limiting funded status volatility. The Retirement Plan Committee monitors the investments in the Master Trust, and seeks to

107

obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the Retirement Plan Committee establishes revised guidelines from time to time.

The asset allocation for the trust and the target allocation prescribed by the investment guidelines by portfolio at December 31 are as follows:
 Percentage of trust assets Target Asset Allocation
 2015 2015
Growth Portfolio52% 55%
Equity securities24%  
Debt securities (a)14%  
Alternative investments14%  
Immunizing Portfolio46%
44%
Debt securities (a)40%  
Derivatives6%  
Liquidity Portfolio2% 1%
Total100%
100%
(a)Includes commingled debt funds, which Talen Energy treats as debt securities for asset allocation purposes.

Prior to the spinoff, the assets of the Talen Montana pension plan were invested solely in a master trust maintained by PPL. The fair value of this plan's assets of $170 million at December 31, 2014 represented an interest of approximately 4% in PPL's master trust.

The fair value of net assets in the Master Trust by asset class and level within the fair value hierarchy was:
 December 31, 2015
 Fair Value Measurement Using
 Total Level 1 Level 2 Level 3
Talen Energy Retirement Plans Master Trust       
Cash and cash equivalents$108
 $108
 $—
 $—
Equity securities:
      
U.S.:
      
Large-cap90
 23
 67
 —
Small-cap33
 33
 —
 —
International190
 —
 190
 —
Commingled debt273
 —
 273
 —
Debt securities:
      
U.S. Treasury and U.S. government sponsored agency192
 189
 3
 —
Corporate231
 —
 231
 —
International government1
 —
 1
 —
Other3
 —
 3
 —
Alternative investments:
      
Commodities28
 —
 28
 —
Real estate48
 —
 48
 —
Private equity31
 —
 —
 31
Hedge funds69
 —
 69
 —
Derivatives:
      
Interest rate swaps32
 —
 32
 —
Other5
 —
 5
 —
Talen Energy Retirement Plans Master Trust assets, at fair value$1,334

$353

$950

$31
        
Receivables and payables, net (a)(31)      
401(h) accounts restricted for other postretirement benefit obligations(29)      
Total Talen Energy Retirement Plans Master Trust pension assets$1,274
      
(a)Receivables and payables represent amounts for investments sold/purchased, but not yet settled along with interest and dividends earned, but not yet received.

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A reconciliation of the Master Trust assets classified as Level 3 at December 31, 2015 is as follows:
 
Private
equity
Balance at beginning of period$—
Acquisitions (a)35
Purchases, sales and settlements(4)
Balance at end of period$31
(a)Transferred from a master trust maintained by PPL.

The fair value measurements of cash and cash equivalents are based on the amounts on deposit.

The market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and passively managed investments that are managed against various equity indices.

Investments in commingled equity and debt funds are categorized as equity securities and are classified as Level 2. The fair value measurements for Level 2 investments are based on firm quotes of net asset values per share, which are not considered obtained from a quoted price in an active market. Investments in commingled equity funds include funds that invest in U.S. and international equity securities. Investments in commingled debt funds include funds that invest in a diversified portfolio of emerging market debt obligations, as well as funds that invest in investment grade long-duration fixed-income securities.

The fair value measurements of debt securities are generally based on evaluations that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. The fair value of debt securities is generally measured using a market approach, including the use of pricing models which incorporate observable inputs. Common inputs include benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as payment data, future predicted cash flows, collateral performance and new issue data. For the Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries and investments in debt securities issued by foreign governments and corporations.

Investments in commodities represent ownership interest of a commingled fund that is invested in a portfolio of exchange-traded futures and forward contracts in commodities to obtain broad exposure to all principal groups in the global commodity markets, including energy, agriculture, livestock and metals (both precious and industrial) using proprietary commodity trading strategies. Redemptions can be made the 15th calendar day and last calendar day of the month with a specified notification period. The fund's fair value is based upon a value as calculated by the fund's administrator.

Investments in real estate represent an investment in a partnership whose purpose is to manage investments in core U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The manager is focused on properties with high occupancy rates with quality tenants. This results in a focus on high income and stable cash flows with appreciation being a secondary factor. Core real estate generally has a lower degree of leverage when compared with more speculative real estate investing strategies. The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value.

Investments in private equity represent interests in partnerships in private equity fund of funds that use a number of diverse investment strategies. Two of the partnerships have limited lives of ten years, while the third has a life of 15 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. The Master Trust has unfunded commitments of $12 million that may be required during the lives of the partnerships. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.

Investments in hedge funds represent investments in three hedge fund of funds. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver

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positive returns under most market conditions. Major investment strategies for the hedge fund of funds include long/short equity, market neutral, distressed debt, and relative value. Generally, shares may be redeemed within 60 to 95 days with prior written notice. The funds are subject to short term lockups and have limitations on the amount that may be withdrawn based on a percentage of the total net asset value of the fund, among other restrictions. All withdrawals are subject to the general partner's approval. The fair value for two of the funds has been estimated using the net asset value per share and the third fund's fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.

The fair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard industry models. These instruments primarily include interest rate swaps, which are valued based on the swap details, such as swap curves, notional amount, index and term of index, reset frequency and payer/receiver credit ratings.

Plan Assets - Other Postretirement Benefit Plans

Prior to the spinoff from PPL, the other postretirement benefit plan assets were invested by PPL in VEBA trusts and a 401(h) account, maintained by PPL.

The investment strategy with respect to other postretirement benefit obligations is to fund VEBA trusts and/or 401(h) accounts with voluntary contributions, when appropriate, and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the Master Trust, other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities, but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes. The asset allocation for the VEBA trusts and the target allocation, by asset class, at December 31 are detailed below.
 Percentage of plan assetsTarget Asset Allocation
 2015 2015
Asset Class   
U.S. Equity securities53% 45%
Debt securities46% 50%
Cash and cash equivalents1% 5%
Total100% 100%

The fair value of assets in the other postretirement benefit plans by asset class and level within the fair value hierarchy was:
 December 31, 2015
 Fair Value Measurement Using
 Total Level 1 Level 2 Level 3
U.S. Equity securities:
      
Large-cap$26
 $—
 $26
 $—
Commingled debt23
 —
 23
 —
Total VEBA trust assets, at fair value49
 $—
 $49
 $—
401(h) account assets29
      
Total other postretirement benefit plan assets$78
      

Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Fair value measurements are not obtained from a quoted price in an active market but are based on firm quotes of net asset values per share as provided by the trustee of the fund. Redemptions can be made daily on this fund.

Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade long-duration fixed income securities. Redemptions can be made weekly on these funds.


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Expected Cash Flows - Defined Benefit Plans

Talen Energy Supply's defined benefit pension plans have the option to utilize available prior year credit balances to meet current and future contribution requirements. Talen Energy expects to contribute $40 million to its defined benefit pension plans in 2016.

Talen Energy is not required to make contributions to its other postretirement benefit plans.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the plans.
 Pension Other Postretirement Benefit Payment
2016$75
 $2
201781
 3
201887
 5
201992
 7
202098
 9
2021-2025538
 63

Savings Plans

Substantially all employees of Talen Energy are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were $16 million in 2015, $14 million in 2014 and $12 million in 2013.

Separation Benefits

Talen Energy Supply and certain subsidiaries provide separation benefits to eligible employees. These benefits may be provided in the case of separations due to performance issues, loss of job related qualifications or organizational changes. Generally, applicable employees separated are eligible for cash severance payments, outplacement services and a single sum payment approximating the dollar amount of premium payments that would be incurred for continuation of group health and welfare coverage. Separation benefits for certain bargaining unit employees also include enhanced pension and postretirement medical benefits. Separation benefits are recorded when such amounts are probable and estimable.

See Note 1 for a discussion of separation benefits related to the spinoff and Note 11 for a discussion of separation benefits related to the one-time voluntary retirement window offered in 2014 to certain bargaining unit employees as part of the new three-year labor agreement with IBEW local 1600. Separation benefits were not significant in 2013.


111

10. Jointly Owned Facilities

At December 31, 2015 and 2014 the Talen Energy Balance Sheets reflect the owned interests in the facilities below.
 Ownership Interest Electric Plant Other Property Accumulated Depreciation Construction Work in Progress
December 31, 2015         
Generating Plants         
Susquehanna90.00% $4,791
 $—
 $3,639
 $148
Conemaugh16.25% 326
 —
 156
 7
Keystone12.34% 218
 —
 111
 3
Colstrip Units 1 & 250.00% 48
 —
 5
 2
Colstrip Units 330.00% 30
 —
 2
 3
Merill Creek Reservoir8.37% —
 22
 16
 —
          
December 31, 2014         
Generating Plants         
Susquehanna90.00% $4,746
 $—
 $3,591
 $117
Conemaugh16.25% 330
 —
 141
 2
Keystone12.34% 213
 —
 102
 2
Colstrip Units 1 & 250.00% 16
 —
 4
 3
Colstrip Unit 330.00% 16
 —
 2
 2
Merill Creek Reservoir8.37% —
 22
 15
 —

Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs associated with the plants is included in the corresponding operating expenses on the Statements of Income.

Talen Montana and NorthWestern have a sharing agreement that governs each party's responsibilities and rights relating to the operation of Colstrip Units 3 and 4. Under the terms of that agreement, each party is responsible for 15% of the total non-coal operating and construction costs of Colstrip Units 3 and 4, regardless of whether a particular cost is specific to Colstrip Unit 3 or 4, and is entitled to take up to the same percentage of the available generation from Units 3 and 4.

11.  Commitments and Contingencies

Energy Purchase and Sales Commitments

Energy Purchase Commitments

Talen Energy enters into long-term energy and energy related contracts which include commitments to purchase:
 Contract Type
 Fuels (a) Limestone Natural Gas Storage Natural Gas Transportation Power, excluding wind RECs Wind Power
Maximum Maturity Date2027 2030 2026 2034 2021 2020 2027

(a)As a result of depressed wholesale market prices for electricity and natural gas. Talen Energy has experienced a shift in the dispatching of its generation fleet from coal-fired to combined-cycle natural gas-fired generation. This reduction in coal-fired generation output has resulted in a surplus of coal inventory at certain of Talen Energy's Pennsylvania plants. To mitigate the risk of oversupply, Talen Energy incurred pre-tax charges of $41 million during 2015 in connection with an agreement to reduce its 2015 through 2018 contracted coal deliveries. These charges were recorded to "Fuel" on the Statement of Income.

Energy Sale Commitments

In connection with its marketing activities or hedging strategies for its power plants, Talen Energy has entered into long-term power sales contracts that extend into 2020.


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Legal Matters

Legal Proceedings

Talen Energy is involved in the following legal proceedings, claims and litigation.  Talen Energy believes that it has meritorious defenses in connection with its current legal proceedings, claims and litigation, and it intends to vigorously contest each of them. However, there can be no assurance that it will be successful in its efforts.

No estimate of the possible loss or range of loss in excess of amounts accrued, if any, can be made at this time regarding any of the matters specifically described below because the inherently unpredictable nature of legal proceedings may be exacerbated by various factors such as ongoing discovery, significant facts that are in dispute, the stage of the proceeding and the wide range of potential outcomes for any such matter. As a result, any losses actually incurred could be substantial.

Sierra Club Litigation

In March 2013, the Sierra Club and MEIC filed a unanimous settlement agreement.complaint in the U.S. District Court, District of Montana, Billings Division against Talen Montana and the other Colstrip Steam Electric Station (Colstrip) owners: Avista Corporation, Puget Sound Energy, Portland General Electric Company, NorthWestern Corporation and PacifiCorp. Talen Montana operates Colstrip on behalf of the owners. The complaint alleged certain violations of the Clean Air Act, including New Source Review, Title V and opacity requirements and listed 39 separate claims for relief.  The complaint requested injunctive relief and civil penalties on average of $36,000 per day per violation, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects.

In July 2013, the Sierra Club and MEIC filed an additional Notice of Intent to Sue, identifying additional plant projects that are alleged not to be in compliance with the Clean Air Act and, in September 2013, filed an amended complaint.  The amended complaint dropped all claims regarding pre-2001 plant projects, as well as the plaintiffs' Title V and opacity claims.  It did, however, add claims with respect to a number of post-2000 plant projects, which effectively increased the number of projects subject to the litigation by about 40.  Talen Montana and the other Colstrip owners filed a motion to dismiss the amended complaint in October 2013.  In May 2014, the court dismissed the plaintiffs' independent Best Available Control Technology claims and their Prevention of Significant Deterioration (PSD) claims for three projects, but denied the owners' motion to dismiss the plaintiffs' other PSD claims on statute of limitation grounds.  In August 2014, the Sierra Club and MEIC filed a second amended complaint.  This complaint includes the same causes of action articulated in the first amended complaint, but in regard to only eight projects done between 2001 and 2013.  In September 2014, the Colstrip owners filed an answer to the second amended complaint.  Discovery closed in the first quarter of 2015, and in April, the plaintiffs indicated they intend to pursue claims related to only four of the remaining projects. The magistrate judge entered an order on the parties' motions for summary judgment on December 31, 2015. The judgment dismissed two of the plaintiffs' four remaining claims and provided more preferable legal standards for the remaining two claims. The case has been bifurcated as to liability and remedy, and the liability trial is currently set for May 2016. A trial date with respect to remedy, if there is a finding of liability, has not been scheduled.

Notice of Intent to File Suit

In October 2014, Talen Energy received a notice letter from the Chesapeake Bay Foundation (CBF) alleging violations of the Clean Water Act and Pennsylvania Clean Streams Law at the Brunner Island generation plant.  The letter was sent to Brunner Island, LLC and the PADEP and is intended to provide notice of the alleged violations and CBF's intent to file suit in Federal court after expiration of the 60 day statutory notice period.  Among other things, the settlement provided for increases in annual base electric ratesletter alleges that Brunner Island, LLC failed to comply with the terms of $34 million at LG&Eits National Pollutant Discharge Elimination System permit and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E.  The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU.  The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%.  On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement.  The new rates became effective on January 1, 2013.  In additionassociated regulations related to the increased base rates,application of nutrient credits to the KPSC approvedfacility's discharges of nitrogen into the Susquehanna River.  The letter also alleges that PADEP has failed to ensure that credits generated from nonpoint source pollution reduction activities that Brunner Island, LLC applies to its discharges meet the eligibility and certification requirements under PADEP's nutrient trading program regulations.  If a gas line tracker mechanism for LG&Elawsuit is filed by CBF, Talen Energy would expect CBF to provide for recoveryseek injunctive relief, monetary penalties, fees and costs of costs associated with LG&E's gas main replacement program, gas service lines and risers.litigation.  

Independent Transmission OperatorsMontana Regional Haze

In September 2012, LG&Ethe EPA Region 8 developed a regional haze Federal Implementation Plan (FIP) for Montana. The final FIP assumed no additional controls for Corette or Colstrip Units 3 and KU completed4, but proposed stricter limits for Corette and Colstrip Units 1 and 2. Talen Montana was meeting these stricter permit limits at Corette without any significant changes to operations, although other requirements led to the transitionsuspension of their independent transmission operator contractual arrangements from Southwest Power Pool, Inc.operations and retirement of Corette in March 2015. The stricter limits at

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Colstrip Units 1 and 2 would require additional controls to TranServ International, Inc.  This change had previously received approvalsmeet more stringent nitrogen oxides and sulfur dioxide limits, the cost of which could be significant. Both Talen Montana and environmental groups appealed the final FIP to the U.S. Court of Appeals for the Ninth Circuit where oral argument was heard in May 2014. On June 9, 2015, the Ninth Circuit issued a decision that vacated as arbitrary and capricious the portions of the FERC and the KPSC.
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(PPL, LKE and LG&E)

CPCN Filing

In October 2012, LG&E filed an application with the KPSC to construct a new wet scrubber to serve Unit 3 at the Mill Creek Generating Station.  The application partially modifies the existing authority granted by the KPSC in 2011, which authorized LG&E to build two new scrubbers to serve Mill CreekFIP setting stricter emissions limits for Colstrip Units 1 and 2 and anotherCorette. The Ninth Circuit upheld the EPA's decision not to serve Mill Creek Unitrequire further emissions reductions at Colstrip Units 3 and 4. Additionally, authority was granted allowingThe Ninth Circuit opinion requires the Mill Creek Unit 3EPA to be served bynow reissue a FIP that is consistent with the existing Unit 4 scrubber.  The CPCN sought approvalopinion.

Colstrip Wastewater Facility Administrative Order on Consent

Talen Montana is party to construct a new wet scrubberan Administrative Order on Mill Creek Unit 3 insteadConsent (AOC) with the MDEQ related to operation of utilizing the Unit 4 scrubber.  In February 2013, LG&E received the requested KPSC approval to construct a new wet scrubber to serve Unit 3wastewater facilities at the Mill Creek Generating Station.Colstrip power plant. In September 2012, Earthjustice, on behalf of Sierra Club, MEIC, and the National Wildlife Federation, filed an affidavit under Montana's Major Facility Siting Act (MFSA) that sought review of the AOC by Montana's Board of Environmental Review. Talen Montana elected to have this proceeding conducted in Montana state district court, and in October 2012, Earthjustice filed a petition for review in Montana state district court in Rosebud County. This matter was stayed in December 2012 pending the outcome of separate litigation where the same environmental groups challenged the AOC in a writ of mandamus. That litigation was resolved in May 2013 when defendants Talen Montana and MDEQ won their motions to dismiss the matter, and the environmental groups did not appeal. In April 2014, Earthjustice filed successful motions for leave to amend the petition for review and to lift the stay. Talen Montana and the MDEQ responded to the amended petition and filed partial motions to dismiss in July 2014, which were denied in October 2014. Discovery closed in October 2015, summary judgment motions on behalf of all parties are pending, and a bench trial is set for April 2016.

Storm CostsOther

In August 2011, a strong storm hit LG&E's service area causing significant damage and widespread outages for approximately 139,000 customers.  LG&E filed an application with the KPSC in September 2011, requesting approval of a regulatory asset recorded to defer, for future recovery, $8 million in incremental operation and maintenance expenses relatedaddition to the storm restoration.  An order was received in December 2011 granting the request.  On December 20, 2012, the KPSCabove matters, from time-to-time in the approvalordinary course of its business Talen Energy may be subject to other legal proceedings, claims and litigation. While the unanimous rate case settlement agreement, authorized regulatory asset recovery effective January 1, 2013, over a five year period.

Pennsylvania Activities(PPLoutcome of these legal proceedings, claims and PPL Electric)

Rate Case Proceeding

In March 2012, PPL Electric filed a request withlitigation is uncertain, the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013.  In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million.  The approved rates became effective January 1, 2013.

Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order.  PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.  See "Storm Costs" below for additional information regarding Hurricane Sandy.

ACT 129

Act 129 requires Pennsylvania Electric Distribution Companies (EDCs) to meet specified goals for reduction in customer electricity usage and peak demand by specified dates.  EDCslikely results are not meeting the requirements of Act 129 are exposed to significant penalties.

Under Act 129, EDCs must file an energy efficiency and conservation plan (EE&C Plan) with the PUC and contract with conservation service providers to implement allexpected, either individually or a portion of the EE&C Plan.  Act 129 requires EDCs to reduce overall electricity consumption by 1.0% by May 2011 and, by May 2013, reduce overall electricity consumption by 3.0% and reduce peak demand by 4.5%.  The peak demand reduction must occur for the 100 hours of highest demand, which is determined by actual demand reduction during the June 2012 through September 2012 period.  EDCs will be able to recover the costs (capped at 2.0% of the EDC's 2006 revenue) of implementing their EE&C Plans.  In October 2009, the PUC approved PPL Electric's EE&C Plan, and in March 2012 confirmed that PPL Electric met the 2011 requirement.  PPL Electric will determine if it met the peak demand reduction target and the May 2013 energy reduction target after it completes the final program evaluation on November 5, 2013.

Act 129 requires the PUC to evaluate the costs and benefits of the EE&C program by November 30, 2013 and adopt additional reductions if the benefits of the program exceed the costs.  In August 2012, after receiving input from stakeholders, the PUC issued a Final Implementation Order establishing a three-year Phase II program, ending May 31, 2016, with individual consumption reduction targets for each EDC.  PPL Electric's reduction target is 2.1%.  The PUC did not establish demand reduction targets for the Phase II program.  PPL Electric filed its Phase II EE&C Plan with the PUC on November 15, 2012 and the PUC is expected to issue its decision in March 2013. Act 129 also requires the Default Service Provider (DSP) to provide electric generation supply service to customers pursuant to a PUC-approved default service procurement plan through auctions, requests for proposal and bilateral contracts at the sole discretion of the DSP.  Act 129 requires a mix of spot market purchases, short-term contracts and long-term contracts (4 to 20
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years), with long-term contracts limited to 25% of load unless otherwise approved by the PUC.  The DSP will be able to recover the costs associated with a competitive procurement plan.

The PUC has approved PPL Electric's procurement plan for the period January 1, 2011 through May 31, 2013, and PPL Electric concluded all competitive solicitations to procure power for its PLR obligations under that plan.

The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015.  PPL Electric filed its plan in May 2012.  In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity from the competitive retail market.  In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.

Smart Meter Rider

Act 129 also requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years.  Under Act 129, EDCs will be able to recover the costs of providing smart metering technology.  In August 2009, PPL Electric filed its proposed smart meter technology procurement and installation plan with the PUC.  All of PPL Electric's metered customers currently have smart meters installed at their service locations.  PPL Electric's current advanced metering technology generally satisfies the requirements of Act 129 and does not need to be replaced.  In June 2010, the PUC entered its order approving PPL Electric's smart meter plan with several modifications.  In compliance with the order, in the third quarter of 2010, PPL Electric submitted a revised plan with a cost estimate of $38 million to be incurred over a five-year period, beginning in 2009, and filed its Section 1307(e) cost recovery mechanism, the Smart Meter Rider (SMR) to recover these costs beginning January 1, 2011.  In December 2010, the PUC approved PPL Electric's SMR which reflects the costs of its smart meter program plus a return on its Smart Meter investments.  The SMR, which became effective January 1, 2011, contains a reconciliation mechanism whereby any over- or under-recovery from customers is either refunded to or collected from customers in the subsequent year.  In August 2011, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter plan in 2011 and its planned actions for 2012.  PPL Electric also submitted revised SMR charges which became effective January 1, 2012.  In August 2012, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter plan in 2012 and its planned actions for 2013.  PPL Electric also submitted revised SMR charges which became effective January 1, 2013.

PUC Investigation of Retail Electricity Market

In April 2011, the PUC opened an investigation of Pennsylvania's retail electricity market to be conducted in two phases.  Phase one addressed the status of the existing retail market and explored potential changes.  Questions issued by the PUC for this phase of the investigation focused primarily on default service issues.  Phase two was initiated in July 2011 to develop specific proposals for changes to the retail market and default service model.  In December 2011, the PUC issued a final order providing guidance to EDCs on the design of their next default service procurement plan filings.  In December 2011, the PUC also issued a tentative order proposing an intermediate work plan to address issues raised in the investigation.  In March 2012, the PUC entered a final order on the intermediate work plan, issued three possible models for the default service "end state" and held a hearing regarding those three models.  In September 2012, the PUC issued a Secretarial Letter setting forth an "RMI End State Proposal" for discussion.  The PUC issued a tentative implementation order in early November 2012, following which parties had 30 days to provide comment.  PPL Electric and PPL EnergyPlus filed joint comments.  A final implementation order was issued on February 15, 2013.  Although the final implementation order contains provisions that will require numerous modifications to PPL Electric's current default service model for retail customers, those modifications are not expectedaggregate, to have a material adverse effect on PPL Electric's results of operations.

Legislation - Regulatory Procedures and Mechanisms

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms - the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a DSIC.  Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets.  In August 2012, the PUC issued a Final Implementation Order adopting procedures, guidelines and a model tariff for the implementation of Act 11.  Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC.  The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC.  In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC.  The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.
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Storm Costs

During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits.  Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statement of Income.  PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income).  In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.  See "Rate Case Proceeding" above for information regarding PPL Electric's plan to file a proposed Storm Damage Expense Rider with the PUC.

PPL Electric experienced several PUC-reportable storms during 2011 including Hurricane Irene and a late October snow storm.  Total restoration costs were $84 million, of which $54 million were initially recorded in "Other operation and maintenance" on the Statement of Income.  Although PPL Electric had storm insurance coverage with a PPL affiliate, the costs associated with the unusually high number of PUC-reportable storms exceeded policy limits.  Probable insurance recoveries recorded during 2011 were $26.5 million, of which $16 million were included in "Other operation and maintenance" on the Statements of Income.  In December 2011, PPL Electric received orders from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Irene and a late October 2011 snowstorm.  PPL Electric recorded a regulatory asset of $25 million in December 2011 (offset to "Other operation and maintenance" on the Statement of Income).  The PUC granted PPL Electric's recovery of the 2011 storm costs in its final order in the 2012 rate case.  Recovery began in January 2013 and will continue over a five year period.

Federal Matters

FERC Formula Rates (PPL and PPL Electric)

Transmission rates are regulated by the FERC.  PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism.

PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates.  Each update has been subsequently challenged by a group of municipal customers, which challenges have been opposed by PPL Electric.  In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order.  In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges.  Settlement conferences were held in late 2012 and early 2013.  In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that challenge with the 2010 and 2011 challenges.  PPL Electric anticipates that there will be additional settlement conferences held in 2013.  PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.

In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization.  This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC.  At December 31, 2012 and 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets."  In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.               

U.K. Activities(PPL)

Ofgem Review of Line Loss Calculation

WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4.  Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4.  In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability.  In March 2012, Ofgem issued a decision regarding the preferred methodology.  In July 2012, Ofgem issued a
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consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013.  In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013.  In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses.  Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology.  This consultation also confirmed the final decisions will be published by April 2013.  In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date.  PPL cannot predict when this matter will be resolved.

Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period.  That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.

European Market Infrastructure Regulation

Regulation No. 648/2012 of the European Parliament and of the Council, commonly referred to as the European Market Infrastructure Regulation (EMIR), entered into force on August 16, 2012 and the European Commission adopted most of the Regulatory Technical Standards without modification in December 2012.  The EMIR establishes certain transaction clearing and other recordkeeping requirements for parties to over-the-counter derivatives transactions.  Included in the derivative transactions that are subject to EMIR are certain interest rate and currency derivative contracts utilized by WPD.  Generally, WPD is expected to qualify under the EMIR as a non-financial counterparty to the transactions in which it engages and further to qualify for certain exemptions that will relieve WPD from the mandatory clearing obligations imposed by the EMIR.  Although the EMIR will potentially impose significant additional recordkeeping requirements on WPD, the effect of the EMIR is not currently expected to have a significant adverse impact on WPD'sTalen Energy's financial condition or results of operation.operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.

7.  Financing Activities

Credit Arrangements and Short-term Debt

(PPL, PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU)

The Registrants maintainmaintains credit facilitiesarrangements to enhance liquidity and provide credit support, and provide a backstop to commercial paper programs.support. For reporting purposes, on a consolidated basis, the credit facilitiesarrangements of PPLTalen Energy Supply PPL Electric, LG&E and KUits subsidiaries also apply to PPL and the credit facilities of LG&E and KU also apply to LKE.  Talen Energy Corporation.
Revolving Credit Facilities

The following secured revolving credit facilities were in place at:  at December 31, 2015:         
 
Expiration
Date
 Capacity Borrowed (c) Letters of
Credit
Issued		 
Unused
Capacity
 
Talen Energy Supply RCF (a)June 2020 $1,850
 $500
 $163
 $1,187
 
New MACH Gen RCF (b)July 2021 160
 108
 31
 21
 
      Total Credit Facilities  $2,010
 $608
 $194
 $1,208
 

       December 31, 2012 December 31, 2011
                Letters of      Letters of
                Credit Issued       Credit Issued
                and       and
                Commercial       Commercial
       Expiration    Borrowed Paper Unused Borrowed Paper
        Date Capacity (a) Backup Capacity (a) Backup
PPL                    
 WPD Credit Facilities                    
  PPL WW Syndicated                    
   Credit Facility (b) (c) (f) Jan. 2013 £ 150  £ 106   n/a £ 44  £ 111   n/a
  WPD (South West)                    
   Syndicated Credit Facility (c) (f) Jan. 2017   245      n/a   245      n/a
  WPD (East Midlands)                    
   Syndicated Credit Facility (c) (d) (f) Apr. 2016   300          300     £ 70 
  WPD (West Midlands)                    
   Syndicated Credit Facility (c) (d) (f) Apr. 2016   300          300       71 
  Uncommitted Credit Facilities     84     £ 4    80       3 
   Total WPD Credit Facilities (e)   £ 1,079  £ 106  £ 4  £ 969  £ 111  £ 144 
                           
PPL Energy Supply                    
 Syndicated Credit Facility (f) (g) (h) Nov. 2017 $ 3,000     $ 499  $ 2,501     $ 541 
 Letter of Credit Facility (k) Mar. 2013   200   n/a   132    68   n/a   89 
 Uncommitted Credit Facilities (h)     200   n/a   40    160   n/a  n/a
   Total PPL Energy Supply                    
    Credit Facilities   $ 3,400     $ 671  $ 2,729     $ 630 
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       December 31, 2012 December 31, 2011
                Letters of      Letters of
                Credit Issued       Credit Issued
                and       and
                Commercial       Commercial
       Expiration    Borrowed Paper Unused Borrowed Paper
        Date Capacity (a) Backup Capacity (a) Backup
PPL Electric                    
 Syndicated Credit Facility (f) (h) Oct. 2017 $ 300     $ 1  $ 299     $ 1 
 Asset-backed Credit Facility (i) Sept 2013   100      n/a   100      n/a
   Total PPL Electric Credit Facilities   $ 400     $ 1  $ 399     $ 1 
                           
LG&E                    
 Syndicated Credit Facility (f) (h) Nov. 2017 $ 500       55  $ 445       
                           
KU                    
 Syndicated Credit Facility (f) (h) Nov. 2017 $ 400     $ 70  $ 330       
 Letter of Credit Facility (f) (h) (j) Apr. 2014   198       198      n/a $ 198 
   Total KU Credit Facilities   $ 598     $ 268  $ 330     $ 198 

(a)AmountsThe facility is syndicated and provides capacity available for short-term borrowings and up to $925 million of letters of credit. The facility requires Talen Energy Supply to maintain a senior secured net debt to adjusted EBITDA ratio (as defined in the agreement) of less than or equal to 4.50 to 1.00 as of the last day of any fiscal quarter. Talen Energy Supply pays customary fees on the facility and borrowings bear interest at its option at either a defined base rate or LIBOR-based rates, in each case plus an applicable margin. The weighted average interest rate on outstanding borrowings at December 31, 2015 was 2.67%.
(b)
The facility provides capacity available for short-term borrowings and up to $120 million of letters of credit. New MACH Gen pays customary fees on the facility and borrowings bear interest at 12-month LIBOR, plus an applicable margin. The weighted average interest rate on outstanding borrowings at December 31, 2015 was 5.04%.
(c)The amounts borrowed are recorded as "Short-term debt" on the Balance Sheets.Sheet.
(b)In December 2012, the PPL WW credit facility was subsequently replaced with a credit facility expiring in December 2016 and the capacity was increased to £210 million.
(c)The facilities contain financial covenants that require the company to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, calculated in accordance with the credit facility.
(d)Under these facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing.
(e)The total amounts borrowed at December 31, 2012 and 2011 were USD-denominated borrowings of $171 million and $178 million, which equated to £106 million and £111 million at the time of the borrowings.  The interest rates at December 31, 2012 and 2011 were 0.8452% and 1.05%.  At December 31, 2012, the unused capacity of WPD's credit facilities was approximately $1.6 billion.
(f)Each company pays customary fees under its respective facility and borrowings generally bear interest at LIBOR-based rates plus an applicable margin.
(g)In October 2010, PPL Energy Supply borrowed $3.2 billion under this facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE.  Such borrowing bore interest at 2.26% and was refinanced primarily through the issuance of long-term debt by LKE, LG&E and KU and the use of internal funds.  This borrowing and related payments were included in "Net increase (decrease) in short-term debt" on the Statement of Cash Flows.

PPLThe Talen Energy Supply incurred an aggregate of $41 million of fees in 2010RCF was entered into on June 1, 2015 in connection with establishing thisthe completion of the spinoff transaction and replaced Talen Energy Supply's previously existing unsecured syndicated credit facility. Such feesAny outstanding principal amounts under the old facility were initially deferredrepaid prior to the termination of the old facility and amortized through December 2014.  In connection withoutstanding letters of credit were transferred to the reduction in the capacity from $4 billion to $3 billion in December 2010, PPLTalen Energy Supply wrote off $10 million, $6 million after tax,RCF. The facility is secured by liens on a majority of deferred fees,Talen Energy Supply's assets and is guaranteed by certain Talen Energy Supply subsidiaries, which was reflectedguarantees are in "Interest Expense" in the Statementturn secured by liens on assets of Income.
(h)The facilities contain a financial covenant requiring debt to total capitalization not to exceed 65% for PPL Energy Supply and 70% for PPL Electric, LG&E and KU, as calculated in accordance with the facilities and other customary covenants.  Additionally, as it relates to the syndicated credit facilities and subject to certain conditions, PPL Energy Supply may request that its facility's capacity be increased by up to $500 million and PPL Electric and KU each may request up to a $100 million increase in its facility's' capacity.
(i)PPL Electric participates in an asset-backed commercial paper program through which PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis.  The subsidiary has pledged these assets to secure loans from a commercial paper conduit sponsored by a financial institution.

At December 31, 2012 and December 31, 2011, $238 million and $251 millionsuch subsidiaries with an aggregate carrying value of accounts receivable and $106 million and $98 million of unbilled revenue were pledged by the subsidiary under the credit agreement related to PPL Electric's and the subsidiary's participation in the asset-backed commercial paper program.  Based on the accounts receivable and unbilled revenue pledged$7 billion at December 31, 2012,2015. The facility provides the amount available for borrowingoption to raise incremental credit facilities, refinance the loans with debt incurred outside the facility and extend the maturity date of the revolving credit commitments and loans and, if applicable, term loans, subject to certain limitations.

The Talen Energy Supply letter of credit facility and uncommitted credit facilities that existed at December 31, 2014 either expired or matured during the first quarter of 2015. Any previously issued letters of credit under these facilities were either terminated or reissued under the then-outstanding unsecured syndicated credit facility was $100 million.  PPL Electric's sale to its subsidiaryand upon closing of the accounts receivablespinoff were reissued under the Talen Energy Supply RCF described above. During the year ended December 31, 2015, Talen Energy wrote-off $12 million of unamortized fees to "Interest expense" on the Statements of Income as a result of the termination of the prior unsecured syndicated credit facility.

The New MACH Gen RCF is a component of the $642 million First Lien Credit and unbilled revenue is an absoluteGuaranty Agreement, which was outstanding when Talen Energy acquired MACH Gen in November 2015. The First Lien Credit and Guaranty Agreement also contains a Term Loan B as described in "Long-term Debt" below. Obligations under the First Lien Credit and Guaranty Agreement are guaranteed by each of New MACH Gen's subsidiaries and are secured by a first priority security interest, subject to possible shared first lien status with certain permitted hedge and power sale of assets, and PPL Electric does not retain an interestagreements, in these assets.  However, for financial reporting purposes, the subsidiary's financial results are consolidated in PPL Electric's financial statements.  PPL Electric performs certain record-keeping and cash collection functions with respect toall of the assets of New MACH Gen and each guarantor, including the equity interests in return forNew MACH Gen and each guarantor, which assets collectively have an aggregate carrying value of approximately $1 billion at December 31, 2015. Talen Energy is not a servicing fee fromguarantor or obligor of borrowings under the subsidiary.First Lien Credit and Guaranty Agreement.

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(j)KU's letter of credit facility agreement allows for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment.
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(k)In February 2013, PPL Energy Supply extended the expiration date of the agreement to March 2014 and, effective April 2013, the capacity will be reduced to $150 million.
(PPL and PPL Energy Supply)
Other Facilities

PPLTalen Energy Supply maintains a $500 million Facility Agreementagreement expiring June 2017 whereby PPLthat provides Talen Energy Supply has the ability to request up to $500 million of committed unsecured letter of credit capacity at fees to be agreed upon at the time of each request, based on certain market conditions.  At December 31, 2012, PPL2015, Talen Energy Supply hashad not requested any capacity for the issuance of letters of credit under this arrangement.

290
PPLIn December 2015, Talen Energy Supply PPL EnergyPlus, PPL Montour and PPL Brunner Island maintain anTalen Energy Marketing entered into the Amended Secured Energy Marketing and Trading Facility Agreement (Amended STF Agreement) to amend the $800 million secured energy marketingSecured Energy Marketing and tradingTrading Facility Common Agreement, dated as of November 1, 2010. The Amended STF Agreement increased the facility whereby PPL EnergyPlus willcapacity to $1.3 billion. The facility allows Talen Energy Supply to receive credit to be applied to satisfy collateral posting obligations related to itsTalen Energy's energy marketing and trading activities with counterparties participating in the facility. The credit amount is guaranteed by PPLPrior to the Talen Energy Supply, PPLspinoff transactions, Montour, LLC and PPL Brunner Island.  PPL Montour and PPL Brunner Island, haveLLC had guaranteed certain of Talen Energy Marketing's obligations and had granted mortgage liens on their respective generating facilities to secure any amount they may owesuch guarantees. Brunner Island and Montour have since been released as parties. Obligations under their guarantees, which had an aggregate carrying value of $2.7 billion at December 31, 2012.the Amended STF Agreement are secured by the same collateral that secures the Talen Energy Supply RCF described above. The facility expires in November 2017, butis for a five-year term that is subject to an automatic one-year renewalsextension each year until termination under certain conditions.the provisions of the Amended STF Agreement. The initial term expires in December 2020. There were no$54 million of secured obligations outstanding under this facility at December 31, 2012.2015.

In April 2012, PPL Energy Supply increased the capacity of its commercial paper program from $500 million to $750 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility.  At December 31, 2012 and 2011, PPL Energy Supply had $356 million and $400 million of commercial paper outstanding, included in "Short-term debt" on the Balance Sheet, at weighted-average interest rates of 0.50% and 0.53%.Long-term Debt

(PPL and PPL Electric)

In May 2012, PPL Electric increased the capacity of its commercial paper program from $200 million to $300 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary.  Commercial paper issuances are supported by PPL Electric's Syndicated Credit Facility.  PPL Electric had no commercial paperThe following long-term debt was outstanding at December 31, 2012.31:
 2015 2014
 Weighted-Average Rate Maturities    
Senior Unsecured Notes5.41% 2016-2038 $3,713
 $2,193
Senior Secured Notes8.86% 2025 41
 45
Term Loan B6.21% 2022 474
 —
Total Long-term Debt Before Adjustments    4,228
 2,238
        
Fair market value adjustments    (23) (19)
Unamortized premium and (discount), net    (2) (1)
Total Long-term Debt    4,203
 2,218
Less current portion of Long-term Debt, including fair market value adjustment    399
 535
Total Long-term Debt, noncurrent    $3,804
 $1,683

(PPL, LKE, LG&E and KU)

In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide an additional financing source to fund their short-term liquidity needs.  Commercial paper issuances are supported by LG&E's and KU's Syndicated Credit Facilities.  At December 31, 2012, LG&E had $55 million of commercial paper outstanding at a weighted-average interest rate of 0.42% and KU had $70 million of commercial paper outstanding at a weighted-average interest rate of 0.42%, included in "Short-term debt" on the Balance Sheet.

(PPL Energy Supply, LKE, LG&E and KU)

See Note 16 for discussion of intercompany borrowings.

2011 Bridge Facility(PPL)

In March 2011, concurrently and in connection with entering into the agreement to acquire WPD Midlands, PPL Capital Funding and PPL WEM, as borrowers, and PPL, as guarantor, entered into a 364-day unsecured £3.6 billion bridge facility to (i) fund the acquisition and (ii) pay certain fees and expenses in connection with the acquisition.  During 2011, PPL incurred $44 million of fees in connection with establishing the 2011 Bridge Facility, which is reflected in "Interest Expense" on the Statement of Income.  On April 1, 2011, concurrent with the closing of the WPD Midlands acquisition, PPL Capital Funding borrowed an aggregate of £1.75 billion and PPL WEM borrowed £1.85 billion under the 2011 Bridge Facility.  Borrowings bore interest at approximately 2.62%, determined by one-month LIBOR rates plus a spread, based on PPL Capital Funding's senior unsecured debt rating and the length of time from the date of the acquisition closing that borrowings were outstanding.  See Note 10 for additional information on the acquisition.

In accordance with the terms of the 2011 Bridge Facility, PPL Capital Funding's borrowings of £1.75 billion were repaid with approximately $2.8 billion of proceeds received from PPL's issuance of common stock and 2011 Equity Units in April 2011.  In April 2011, PPL WEM repaid £650 million of its 2011 Bridge Facility borrowing.  Such repayment was funded primarily with proceeds received from PPL WEM's issuance of senior notes.  In May 2011, PPL WEM repaid the remaining £1.2 billion of borrowings then-outstanding under the 2011 Bridge Facility, primarily with the proceeds from senior notes issued by WPD (East Midlands) and WPD (West Midlands).

In anticipation of the repayment of a portion of the borrowings under the 2011 Bridge Facility with U.S. dollar proceeds received from PPL's issuance of common stock and 2011 Equity Units and PPL WEM's issuance of U.S. dollar-denominated senior notes, PPL entered into forward contracts to purchase GBP in order to economically hedge the foreign currency exchange rate risk related to the repayment.  See Note 19 for additional information.
291
Long-term Debt (PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

    Weighted-Average   December 31,
    Rate Maturities 2012  2011 
PPL         
U.S.         
 Senior Unsecured Notes (a)4.66% 2013 - 2038 $ 4,506  $ 3,805 
 Senior Secured Notes/First Mortgage Bonds (b) (c) (d) (e)4.19% 2013 - 2041   5,587    5,111 
 Junior Subordinated Notes4.89% 2018 - 2067   2,608    2,608 
 Other6.95% 2014 - 2020   15    15 
   Total U.S. Long-term Debt      12,716    11,539 
             
U.K.         
 Senior Unsecured Notes (f)5.71% 2016 - 2040   6,111    5,862 
 Index-linked Senior Unsecured Notes (g)1.85% 2043 - 2056   608    581 
   Total U.K. Long-term Debt (h)      6,719    6,443 
   Total Long-term Debt Before Adjustments      19,435    17,982 
             
 Fair market value adjustments      78    65 
 Unamortized premium and (discount), net      (37)   (54)
   Total Long-term Debt      19,476    17,993 
 Less current portion of Long-term Debt      751    
   Total Long-term Debt, noncurrent    $ 18,725  $ 17,993 
             
PPL Energy Supply         
 Senior Unsecured Notes (a)5.50% 2013 - 2038 $ 2,581  $ 2,581 
 Senior Secured Notes (b)8.31% 2013 - 2025   663    437 
 Other6.00% 2020   5    5 
   Total Long-term Debt Before Adjustments      3,249    3,023 
             
 Fair market value adjustments      22    
 Unamortized premium and (discount), net      1    1 
   Total Long-term Debt      3,272    3,024 
 Less current portion of Long-term Debt      751    
   Total Long-term Debt, noncurrent    $ 2,521  $ 3,024 
             
PPL Electric         
 Senior Secured Notes/First Mortgage Bonds (c) (d)4.60% 2015 - 2041 $ 1,964  $ 1,714 
 Other7.38% 2014   10    10 
   Total Long-term Debt Before Adjustments      1,974    1,724 
             
 Unamortized discount      (7)   (6)
   Total Long-term Debt    $ 1,967  $ 1,718 
             
LKE         
 Senior Unsecured Notes3.31% 2015 - 2021 $ 1,125  $ 1,125 
 Senior Secured Notes/First Mortgage Bonds (c) (e)3.00% 2015 - 2040   2,960    2,960 
   Total Long-term Debt Before Adjustments      4,085    4,085 
             
 Fair market value adjustments      7    7 
 Unamortized discount      (17)   (19)
   Total Long-term Debt    $ 4,075  $ 4,073 
             
LG&E         
 Senior Secured Notes/First Mortgage Bonds (c) (e)2.49% 2015 - 2040 $ 1,109  $ 1,109 
   Total Long-term Debt Before Adjustments      1,109    1,109 
             
 Fair market value adjustments     6   6 
 Unamortized discount      (3)   (3)
   Total Long-term Debt    $ 1,112  $ 1,112 
             
KU         
 Senior Secured Notes/First Mortgage Bonds (c) (e)3.30% 2015 - 2040 $ 1,851  $ 1,851 
   Total Long-term Debt Before Adjustments      1,851    1,851 
             
 Fair market value adjustments     1   1 
 Unamortized discount      (10)   (10)
   Total Long-term Debt    $ 1,842  $ 1,842 
292
(a)Includes $300 million of 5.70% REset Put Securities due 2035 (REPS).  The REPS bear interest at a rate of 5.70% per annum to, but excluding, October 15, 2015 (Remarketing Date).  The REPS are required to be put by existing holders on the Remarketing Date either for (a) purchase and remarketing by a designated remarketing dealer or (b) repurchase by PPL Energy Supply.  If the remarketing dealer elects to purchase the REPS for remarketing, it will purchase the REPS at 100% of the principal amount, and the REPS will bear interest on and after the Remarketing Date at a new fixed rate per annum determined in the remarketing.  PPL Energy Supply has the right to terminate the remarketing process.  If the remarketing is terminated at the option of PPL Energy Supply or under certain other circumstances, including the occurrence of an event of default by PPL Energy Supply under the related indenture or a failed remarketing for certain specified reasons, PPL Energy Supply will be required to pay the remarketing dealer a settlement amount as calculated in accordance with the related remarketing agreement.
(b)Includes lease financing consolidated through a VIE.  See Note 22 for additional information.
(c)Includes PPL Electric's senior secured and first mortgage bonds that are secured by the lien of PPL Electric's 2001 Mortgage Indenture, which covers substantially all electric distribution plant and certain transmission plant owned by PPL Electric.  The carrying value of PPL Electric's property, plant and equipment was approximately $4.3 billion and $3.9 billion at December 31, 2012 and 2011.

LG&E's first mortgage bonds are secured by the lien of the LG&E 2010 Mortgage Indenture, which creates a lien, subject to certain exceptions and exclusions, on substantially all of LG&E's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and the storage and distribution of natural gas.  The aggregate carrying value of the property subject to the lien was $2.7 billion and $2.6 billion at December 31, 2012 and December 31, 2011.

KU's first mortgage bonds are secured by the lien of the KU 2010 Mortgage Indenture, which creates a lien, subject to certain exceptions and exclusions, on substantially all of KU's real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity.  The aggregate carrying value of the property subject to the lien was $4.4 billion and $4.1 billion at December 31, 2012 and December 31, 2011.
(d)Includes PPL Electric's series of senior secured bonds that secure its obligations to make payments with respect to each series of Pollution Control Bonds that were issued by the LCIDA and the PEDFA on behalf of PPL Electric.  These senior secured bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such Pollution Control Bonds.  These senior secured bonds were issued under PPL Electric's 2001 Mortgage Indenture and are secured as noted in (c) above.  This amount includes $224 million that may be redeemed at par beginning in 2015 and $90 million that may be redeemed, in whole or in part, at par beginning in October 2020 and are subject to mandatory redemption upon determination that the interest rate on the bonds would be included in the holders' gross income for federal tax purposes.
(e)Includes LG&E's and KU's series of first mortgage bonds that were issued to the respective trustees of tax-exempt revenue bonds to secure its respective obligations to make payments with respect to each series of bonds.  The first mortgage bonds were issued in the same principal amount, contain payment and redemption provisions that correspond to and bear the same interest rate as such tax-exempt revenue bonds.  These first mortgage bonds were issued under the LG&E 2010 Mortgage Indenture and the KU 2010 Mortgage Indenture and are secured as noted in (c) above.  The related tax-exempt revenue bonds were issued by various governmental entities, principally counties in Kentucky, on behalf of LG&E and KU.  The related revenue bond documents allow LG&E and KU to convert the interest rate mode on the bonds from time to time to a commercial paper rate, daily rate, weekly rate, term rate of at least one year or, in some cases, an auction rate or a LIBOR index rate.

At December 31, 2012, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a term rate mode totaled $321 million for LKE, comprised of $294 million and $27 million for LG&E and KU.  At December 31, 2012, the aggregate tax-exempt revenue bonds issued on behalf of LG&E and KU that were in a variable rate mode totaled $604 million for LKE, comprised of $280 million and $324 million for LG&E and KU.

Several series of the tax-exempt revenue bonds are insured by monoline bond insurers whose ratings were reduced due to exposures relating to insurance of sub-prime mortgages.  Of the bonds outstanding, $231 million are in the form of insured auction rate securities, wherein interest rates are reset either weekly or every 35 days via an auction process.  Beginning in late 2007, the interest rates on these insured bonds began to increase due to investor concerns about the creditworthiness of the bond insurers.  During 2008, interest rates increased, and LG&E and KU experienced failed auctions when there were insufficient bids for the bonds.  When a failed auction occurs, the interest rate is set pursuant to a formula stipulated in the indenture.  As noted above, the instruments governing these auction rate bonds permit LG&E and KU to convert the bonds to other interest rate modes.

Certain variable rate tax-exempt revenue bonds totaling $348 million at December 31, 2012, are subject to tender for purchase by LG&E and KU at the option of the holder and to mandatory tender for purchase by LG&E and KU upon the occurrence of certain events.
(f)Includes £225 million ($361 million at December 31, 2012) of notes that may be redeemed, in total but not in part, on December 21, 2026, at the greater of the principal value or a value determined by reference to the gross redemption yield on a nominated U.K. Government bond.
(g)The principal amount of the notes issued by WPD (South West) and WPD (East Midlands) are adjusted based on changes in a specified index, as detailed in the terms of the related indentures.  The adjustment to the principal amounts from 2011 to 2012 was an increase of approximately £9 million ($14 million) resulting from inflation.  In addition, this amount includes £225 million ($361 million at December 31, 2012) of notes issued by WPD (South West) that may be redeemed, in total by series, on December 1, 2026, at the greater of the adjusted principal value and a make-whole value determined by reference to the gross real yield on a nominated U.K. government bond.
(h)Includes £3.3 billion ($5.3 billion at December 31, 2012) of notes that may be put by the holders back to the issuer for redemption if the long-term credit ratings assigned to the notes are withdrawn by any of the rating agencies (Moody's, S&P or Fitch) or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event which includes the loss of, or a material adverse change to, the distribution licenses under which the issuer operates.

None of the outstanding debt securities noted above have sinking fund requirements.  The aggregate maturities of long-term debt for the periods 2013 through 2017 and thereafter are as follows.
293
     PPL            
     Energy PPL         
  PPL Supply Electric LKE LG&E KU
                   
2013  $ 751  $ 751             
2014    328    318  $ 10          
2015    1,317    317    100  $ 900  $ 250  $ 250 
2016   ��828    368             
2017    118    18             
Thereafter   16,093    1,477    1,864    3,185    859    1,601 
Total $ 19,435  $ 3,249  $ 1,974  $ 4,085  $ 1,109  $ 1,851 
follows:

Long-term Debt and Equity Securities Activities
2016 2017 2018 2019 2020 Thereafter Total
$396
 $5
 $424
 $1,244
 $179
 $1,980
 $4,228

(PPL)

In April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock.  In conjunction with that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.Long-term Debt Activity

In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9May 2015, Talen Energy Supply issued $600 million shares of PPL common stock.  Settlement of these initial forward sale agreements will occur no later than April 2013.  As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the 591 thousand additional shares of PPL common stock.  Settlement of the subsequent forward sale agreements will occur no later than July 2013.  Upon any physical settlement of any forward sale agreement, PPL will issue and deliver to the forward counterparties shares of its common stock in exchange for cash proceeds per share equal to the forward sale price.  The forward sale price will be calculated based on an initial forward price of $27.02 per share reduced during the period the contracts are outstanding as specified in the forward sale agreements.  PPL may, in certain circumstances, elect cash settlement or net share settlement for all or a portion of its rights or obligations under the forward sale agreements.

PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements.  PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.

The forward sale agreements are classified as equity transactions.  As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements.  Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method.  See Note 4 for information on the forward sale agreements impact on the calculation of diluted EPS.

In April 2012, WPD (East Midlands) issued £100 million aggregate principal amount of 5.25%6.50% Senior Unsecured Notes due 2023.  WPD (East Midlands)2025. Talen Energy Supply received proceeds of £111$591 million, which equated to $178 million at the time of issuance, net of underwriting fees.  The net proceedsfees, which were used for general corporate purposes.

In June 2012, PPL Capital Funding issued $400 millionrepayment of 4.20% Senior Notes due 2022.short-term debt. The notes may be redeemed at PPL Capital Funding'sTalen Energy Supply's option, in whole at any time or in part from time to time, prior to maturityJune 1, 2020 at a price equal to 100% of their principal amount plus a make-whole premium and on or after June 1, 2020 at specified redemption prices. PPL Capital Funding received proceedsIn addition, on or prior to June 1, 2018, up to 35% of $396 million, net of a discount and underwriting fees, which were used for general corporate purposes.

In August 2012, PPL Capital Funding redeemed at par, plus accrued interest, the $99 million outstanding principal amount of its 6.85% Senior Notes due 2047.

In October 2012, PPL Capital Funding issued $400 million of 3.50% Senior Notes due 2022.  The notes may be redeemed by Talen Energy Supply with proceeds from certain equity offerings at PPL Capital Funding's option any time priora price equal to maturity at make-whole redemption prices.  PPL Capital Funding received proceeds106.5% of $397 million, net of a discount and underwriting fees, which were used to repay short-term debt obligations, including commercial paper borrowings and for general corporate purposes.the principal amount.

(PPLIn June 2015, Talen Energy Supply assumed $1.25 billion of RJS Power Holdings LLC's 5.125% Senior Notes due 2019 as a result of the merger of RJS Power Holdings LLC into Talen Energy Supply, by which Talen Energy Supply became the obligor of these notes. In connection with this event and PPL Energy Supply)pursuant to the terms of the indenture governing the notes, the coupon on the notes was reduced to 4.625% in July 2015.


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In April 2012, an indirect, wholly owned subsidiary of PPLSeptember 2015, Talen Energy Supply completed the Ironwood Acquisition.  See Note 10 for informationa remarketing of $231 million of Exempt Facilities Revenue Refunding Bonds, Series 2009A due 2038, Series 2009B due 2038, and Series 2009C due 2037 that were issued by PEDFA on the transaction and the long-term debtbehalf of PPL Ironwood, LLC assumed through consolidation as part of the acquisition.
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In February 2013, PPLTalen Energy Supply completed an exchange offerin 2009. All series bore interest at a fixed rate of 3.0% prior to exchange up to all, but not less thanthe remarketing. The Series 2009A Bonds, with a majority, of 8.857% Senior Secured Bonds due 2025 of its wholly owned subsidiary, PPL Ironwood (the "Ironwood Bonds") for newly issued PPL Energy Supply Senior Notes, Series 4.60% due 2021.  A total of $167 million aggregate principal amount of outstanding Ironwood Bonds was exchanged for $212$100 million, aggregate principal amount of PPL Energy Supply Senior Notes, Series 4.60% due 2021.

(PPL and PPL Electric)

See Note 3 for information regarding PPL Electric's June 2012 redemption of all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share.

In August 2012, PPL Electric issued $250 million of 2.50% First Mortgage Bonds due 2022.  The notes may be redeemed at PPL Electric's option any time prior to maturity at make-whole redemption prices.  PPL Electric received proceeds of $247 million, net of a discount and underwriting fees.  The net proceeds were used to repay short-term debt incurred to fund PPL Electric's redemption of its 6.25% Series Preference Stock in June 2012 and for other general corporate purposes.

(PPL and LKE)

In June 2012, LKE completed an exchange of $250 million of 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered with the SEC.

(PPL)

2011 Equity Units

In April 2011, in connection with the acquisition of WPD Midlands, PPL issued 92 million shares of its common stockremarketed at a public offering pricefixed coupon of $25.30 per share, for a total of $2.328 billion.  Proceeds from the issuance were $2.258 billion, net of the $70 million underwriting discount.  PPL also issued 19.55 million 2011 Equity Units at a stated amount per unit of $50.00 for a total of $978 million.  Proceeds from the issuance were $948 million, net of the $30 million underwriting discount.  PPL used the net proceeds6.40% to repay PPL Capital Funding's borrowings under the 2011 Bridge Facility, as discussed above, to pay certain acquisition-related feesmaturity. The Series 2009B Bonds and expenses and for general corporate purposes.

Each 2011 Equity Unit consists of a 2011 Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in $1,000 principal amount of PPL Capital Funding 4.32% Junior Subordinated Notes due 2019 (2019 Notes).

Each 2011 Purchase Contract obligates the holder to purchase, and PPL to sell, for $50.00 a number of shares of PPL common stock to be determined by the average VWAP of PPL's common stock for the 20-trading day period ending on the third trading day prior to May 1, 2014, subject to antidilution adjustments and an early settlement upon a Fundamental Change as follows:

·if the average VWAP equals or exceeds approximately $30.99, then 1.6133 shares (a minimum of 31,540,015 shares);
·if the average VWAP is less than approximately $30.99 but greater than $25.30, a number of shares of common stock having a value, based on the average VWAP, equal to $50.00; and
·if the average VWAP is less than or equal to $25.30, then 1.9763 shares (a maximum of 38,636,665 shares).

If holders elect to settle the 2011 Purchase Contract prior to May 1, 2014, they will receive 1.6133 shares of PPL common stock, subject to antidilution adjustments and an early settlement upon a Fundamental Change.

A holder's ownership interest in the 2019 Notes is pledged to PPL to secure the holder's obligation under the related 2011 Purchase Contract.  If a holder of a 2011 Purchase Contract chooses at any time no longer to be a holder of the 2019 Notes, such holder's obligation under the 2011 Purchase Contract must be secured by a U.S. Treasury security.

Each 2011 Purchase Contract also requires PPL to make quarterly contract adjustment payments at a rate of 4.43% per year on the $50.00 stated amount of the 2011 Equity Unit.  PPL has the option to defer these contract adjustment payments until the 2011 Purchase Contract settlement date.  Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate of 8.75% per year until paid.  Until any deferred contract adjustment payments have been paid, PPL may not declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation paymentSeries 2009C Bonds, with respect to, any of its capital stock, subject to certain exceptions.
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The 2019 Notes are fully and unconditionally guaranteed by PPL as to payment of principal and interest.  The 2019 Notes initially bear interest at 4.32% and are not subject to redemption prior to May 2016.  Beginning May 2016, PPL Capital Funding may, at its option, redeem the 2019 Notes, in whole but not in part, at any time, at par plus accrued and unpaid interest.  The 2019 Notes are expected to be remarketed in 2014 into two tranches, such that neither tranche will have an aggregate principal amount of less than the lesser of $250$131 million, and 50% of the aggregate principal amount of the 2019 Notes to be remarketed.  One tranche will mature on or about the third anniversary of the settlement of the remarketing, and the other tranche will mature on or about the fifth anniversary of such settlement.  Upon a successful remarketing, the interest rate on the 2019 Notes may be reset and the maturity of the tranches may be modified as necessary.  In connection with a remarketing, PPL Capital Funding may elect with respect to each tranche, to extend or eliminate the early redemption date and/or calculate interest on the notes of a tranche onwere remarketed at a fixed or floating rate basis.  If the remarketing fails, holders of the 2019 Notes5.00% for five years, at which time they will have the right to put their notes to PPL Capital Funding on May 1, 2014 for an amount equal to the principal amount plus accrued interest.

Prior to May 2016, PPL Capital Funding may elect at one or more times to defer interest payments on the 2019 Notes for one or more consecutive interest periods until the earlier of the third anniversary of the interest payment due date and May 2016.  Deferred interest payments will accrue additional interest at a rate equal to the interest rate then applicable to the 2019 Notes.  Until any deferred interest payments have been paid, PPL may not,be subject to certain exceptions, (i) declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, (ii) make any payment of principal of, or interest or premium, if any, on, or repay, purchase or redeem any of its debt securities that upon its liquidation ranks equal with, or junior in interest to, the subordinated guarantee of the 2019 Notes by PPL as of the date of issuancemandatory repurchase and (iii) make any payments regarding any guarantee by PPL of securities of any of its subsidiaries (other than PPL Capital Funding) if the guarantee ranks equal with, or junior in interest to, the 2019 Notes as of the date of their issuance.

In the financial statements, the proceeds from the sale of the 2011 Equity Units were allocated to the 2019 Notes and the 2011 Purchase Contracts, including the obligation to make contract adjustment payments, based on the underlying fair value of each instrument at the time of issuance.  As a result, the 2019 Notes were recorded at $978 million, which approximated fair value, as long-term debt.  At the time of issuance, the present value of the contract adjustment payments of $123 million was recorded to other liabilities representing the obligation to make contract adjustment payments, with an offsetting reduction to additional paid-in capital for the issuance of the 2011 Purchase Contracts, which approximated the fair value of each.  The liability is being accreted through interest expense over the three-year term of the 2011 Purchase Contracts.  The initial valuation of the contract adjustment payments is considered a non-cashoptional remarketing. This transaction that is excluded from the Statement of Cash Flows as a non-cash transaction.

In October 2015, Talen Energy Supply's $300 million of 5.70% REset Put Securities due 2035 (REPS) were subject to mandatory tender to the remarketing dealer. However, the remarketing dealer and Talen Energy Supply mutually agreed to terminate the remarketing dealer's right to remarket the REPS and, in 2011.  Costsaccordance with the terms of the REPS, Talen Energy Supply repurchased the REPS at par. The total aggregate consideration paid to issuerepurchase the 2011 Equity Units were primarily allocated on a relative cost basis, resulting in $25REPS was $434 million, being recordedwhich included $300 million of principal and $134 million of remarketing option value paid to "Additional paid-in capital" and $6 million beingthe remarketing dealer. The termination payment to the remarketing dealer was recorded to "Other noncurrent assets"Income (Expense) - net" on the Balance Sheet.2015 Statement of Income and is reflected in "Cash from operating activities" on the 2015 Statement of Cash Flows.

Following the MACH Gen acquisition in November 2015, $475 million of New MACH Gen Term Loan B debt secured under the First Lien Credit and Guaranty Agreement, which is described above, remained outstanding. The Term Loan B provides customary annual amortization paid quarterly and may also be repaid, in whole or in part, beginning in the third quarter of 2016 without any make-whole premium. See Note 4"Credit Arrangements and Short-term Debt - Revolving Credit Facilities" above for EPS considerations relatedinformation regarding guarantees of and security interests with respect to the 2011 Purchase Contracts.First Lien Credit and Guaranty Agreement.

2010 Equity UnitsIn December 2015, Talen Energy Supply announced an "exchange offer" for its 6.5% Senior Unsecured Notes due 2025 that were issued in May 2015. Pursuant to the terms of the notes, Talen Energy Supply offered to exchange all of the outstanding notes for a like principal amount of its 6.5% Senior Notes due 2025 that, have been registered under the Securities Exchange Act of 1933, as amended. In January 2016, the exchange offer was completed with all of the notes exchanged.

In June 2010, in connection with the acquisitionsale of LKE, PPL issued 103.5Talen Ironwood Holdings, LLC, in January 2016, a Talen Ironwood Holdings, LLC subsidiary completed the redemption of $41 million of its 8.857% Senior Secured Notes due 2025 prior to the closing of the sale transaction, which occurred in February 2016. The redemption included the payment of a make whole premium of $14 million, which will be recorded as a component of the expected gain on sale in "Operating Income" on the Statement of Income in 2016. See Note 6 for additional information on the sale of Talen Ironwood Holdings, LLC.

Preferred Stock of Talen Energy Corporation

Talen Energy Corporation is authorized under its Amended and Restated Certificate of Incorporation to issue up to 100 million shares of its commonpreferred stock. No shares of preferred stock were issued or outstanding at a public offering price of $24.00 per share, for a total of $2.484 billion.  Proceeds from the issuance were $2.409 billion, net of the $75 million underwriting discount.  PPL also issued 23 million 2010 Equity Units at a stated amount per unit of $50.00 for a total of $1.150 billion.  Proceeds from the issuance were $1.116 billion, net of the $34 million underwriting discount.December 31, 2015.

Each 2010 Equity Unit consists of a Purchase Contract and, initially, a 5.0% undivided beneficial ownership interest in
$1,000 principal amount of PPL Capital Funding 4.625% Junior Subordinated Notes due 2018 (2018 Notes).

Each 2010 Purchase Contract obligates the holder to purchase, and PPL to sell, for $50.00 a variable number of shares of PPL common stock determined by the average VWAP of PPL's common stock for the 20-trading day period ending on the third trading day prior to July 1, 2013, subject to antidilution adjustments and an early settlement upon a Fundamental Change as follows:

·if the average VWAP equals or exceeds $28.80, then 1.7361 shares (a minimum of 39,930,300 shares);
·if the average VWAP is less than $28.80 but greater than $24.00, a number of shares of common stock having a value, based on the average VWAP, equal to $50.00; and
·if the average VWAP is less than or equal to $24.00, then 2.0833 shares (a maximum of 47,915,900 shares).

If holders elect to settle the 2010 Purchase Contract prior to July 1, 2013, they will receive 1.7361 shares of PPL common stock, subject to antidilution adjustments and an early settlement upon a Fundamental Change.
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A holder's ownership interest in the 2018 Notes is pledged to PPL to secure the holder's obligation under the related 2010 Purchase Contract.  If a holder of a 2010 Purchase Contract chooses at any time to no longer be a holder of the 2018 Notes, such holder's obligation under the 2010 Purchase Contract must be secured by a U.S. Treasury security.

Each 2010 Purchase Contract also requires PPL to make quarterly contract adjustment payments at a rate of 4.875% per year on the $50.00 stated amount of the 2010 Equity Unit.  PPL has the option to defer these contract adjustment payments until the 2010 Purchase Contract settlement date.  Deferred contract adjustment payments will accrue additional contract adjustment payments at the rate of 9.5% per year until paid.  Until any deferred contract adjustment payments have been paid, PPL may not declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, subject to certain exceptions.

The 2018 Notes are fully and unconditionally guaranteed by PPL as to payment of principal and interest.  The 2018 Notes initially bear interest at 4.625% and are not subject to redemption prior to July 2015.  Beginning July 2015, PPL Capital Funding may, at its option, redeem the 2018 Notes, in whole but not in part, at any time, at par plus accrued and unpaid interest.  The 2018 Notes are expected to be remarketed in 2013 in two tranches, such that neither tranche will have an aggregate principal amount of less than the lesser of $300 million and 50% of the aggregate principal amount of the 2018 Notes to be remarketed.  One tranche will mature on or about the third anniversary of the settlement of the remarketing, and the other tranche will mature on or about the fifth anniversary of such settlement.  The 2018 Notes will be remarketed as subordinated, unsecured obligations of PPL Capital Funding, as PPL Capital Funding notified the trustee in September 2010 of its irrevocable election to maintain the subordination provisions of the notes and related guarantees in a remarketing.  Upon a successful remarketing, the interest rate on the 2018 Notes may be reset and the maturity of the tranches may be modified as necessary.  In connection with a remarketing, PPL Capital Funding may elect, with respect to each tranche, to extend or eliminate the early redemption date and/or calculate interest on the notes of a tranche on a fixed or floating rate basis.  If the remarketing fails, holders of the 2018 Notes will have the right to put their notes to PPL Capital Funding on July 1, 2013 for an amount equal to the principal amount plus accrued interest.

Prior to July 2013, PPL Capital Funding may elect at one or more times to defer interest payments on the 2018 Notes for one or more consecutive interest periods until the earlier of the third anniversary of the interest payment due date and July 2015.  Deferred interest payments will accrue additional interest at a rate equal to the interest rate then applicable to the 2018 Notes.  Until any deferred interest payments have been paid, PPL may not, subject to certain exceptions, (i) declare or pay any dividends or distributions on, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, (ii) make any payment of principal of, or interest or premium, if any, on, or repay, purchase or redeem any of its debt securities that upon its liquidation ranks equal with, or junior in interest to, the subordinated guarantee of the 2018 Notes by PPL as of the date of issuance and (iii) make any payments regarding any guarantee by PPL of securities of any of its subsidiaries (other than PPL Capital Funding) if the guarantee ranks equal with, or junior in interest to, the 2018 Notes as of the date of their issuance.

In the financial statements, the proceeds from the sale of the 2010 Equity Units were allocated to the 2018 Notes and the 2010 Purchase Contracts, including the obligation to make contract adjustment payments, based on the underlying fair value of each instrument at the time of issuance.  As a result, the 2018 Notes were recorded at $1.150 billion, which approximated fair value, as long-term debt.  At the time of issuance, the present value of the contract adjustment payments of $157 million was recorded to other liabilities, representing the obligation to make contract adjustment payments, with an offsetting reduction to additional paid-in capital for the issuance of the 2010 Purchase Contracts, which approximated the fair value of each.  The liability is being accreted through interest expense over the three-year term of the 2010 Purchase Contracts.  The initial valuation of the contract adjustment payments is considered a non-cash transaction that was excluded from the Statement of Cash Flows in 2010.  Costs to issue the 2010 Equity Units were primarily allocated on a relative cost basis, resulting in $29 million being recorded to "Additional paid-in capital" and $7 million being recorded to "Other noncurrent assets" on the Balance Sheet.  See Note 4 for EPS considerations related to the 2010 Purchase Contracts.

Legal Separateness(PPL, PPL Energy Supply, PPL Electric and LKE)

The subsidiaries of PPLTalen Energy Corporation are separate legal entities. PPL'sTalen Energy Corporation's subsidiaries are not liable for the debts of PPL.Talen Energy Corporation. Accordingly, creditors of PPLTalen Energy Corporation may not satisfy their debts from the assets of PPL'sTalen Energy Corporation's subsidiaries absent a specific contractual undertaking by a subsidiary to pay PPL'sTalen Energy Corporation's creditors or as required by applicable law or regulation. Similarly, absent a specific contractual undertaking or as required by applicable law or regulation, PPLTalen Energy Corporation is not liable for the debts of its subsidiaries, nor are its subsidiaries liable for the debts of one another. Accordingly, creditors of PPL'sTalen Energy Corporation's subsidiaries may not satisfy their debts from the assets of PPLTalen Energy Corporation or its other subsidiaries absent a specific contractual undertaking by PPLTalen Energy Corporation or its other subsidiaries to pay the creditors or as required by applicable law or regulation.
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Similarly, the subsidiaries of PPLTalen Energy Supply PPL Electric and LKE are each separate legal entities. These subsidiaries are not liable for the debts of PPLTalen Energy Supply, PPL Electric and LKE.Supply. Accordingly, creditors of PPLTalen Energy Supply PPL Electric and LKE may not satisfy their debts from the assets of their subsidiaries absent a specific contractual undertaking by a subsidiary to pay the creditors or as required by applicable law or regulation. Similarly, absent a specific contractual undertaking or as required by applicable law or regulation, PPLTalen Energy Supply PPL Electric and LKE areis not liable for the debts of theirits subsidiaries, nor are theirthe subsidiaries liable for the debts of one another. Accordingly, creditors of these subsidiaries may not satisfy their debts from the assets of PPLTalen Energy Supply PPL Electric and LKE (or their other subsidiaries) absent a specific contractual undertaking by that parent or other subsidiary to pay such creditors or as required by applicable law or regulation.


Distributions, Capital Contributions
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As indicated above, certain debt agreements, including, but not limited to, the Talen Energy Supply RCF, the First Lien Credit and Related RestrictionsGuaranty Agreement and the Amended STF Agreement, include contractual undertakings by certain Talen Energy subsidiaries to guarantee the obligations of other Talen Energy entities arising under those agreements.

(PPL)Distribution Related Restrictions for Talen Energy Corporation

In November 2012, PPL declaredCertain of Talen Energy's debt agreements include covenants that could effectively restrict the payment of distributions, loans or advances, either directly to Talen Energy Corporation or to Talen Energy Supply or one of its quarterly common stock dividend, payable January 2, 2013, at 36.0 cents per share (equivalent to $1.44 per annum).  In February 2013, PPL declared its quarterly common stock dividend, payable April 1, 2013, at 36.75 cents per share (equivalent to $1.47 per annum).  Future dividends, declared at the discretion of the Board of Directors, will depend upon future earnings, cash flows, financial and legal requirements and other factors.

Neither PPL Capital Funding nor PPL may declare or pay any cash dividend or distribution on its capital stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067.  Subject to certain exceptions, PPL may not declare or pay any dividend or distribution on its capital stock until any deferred interest payments on its 4.625% Junior Subordinated Notes due 2018 and its 4.32% Junior Subordinated Notes due 2019 have been paid and deferred contract adjustment payments on PPL's Purchase Contracts have been paid.subsidiaries. At December 31, 2012, no payments were deferred on any series2015, $3.3 billion of junior subordinated notes or the Purchase Contracts.

(PPL, PPL Electric, LKE, LG&E and KU)

PPL relies on dividends or loans from itsTalen Energy Corporation subsidiaries to fund PPL's dividends to its common shareholders.  The net assets of certain PPL subsidiaries are subject to legal restrictions.  LKE primarily relies on dividends from its subsidiaries to fund its dividends to PPL.  LG&E, KU and PPL Electric are subject to Section 305(a) of the Federal Power Act, which makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in capital account."  The meaning of this limitation has never been clarified under the Federal Power Act.  LG&E, KU and PPL Electric believe, however, that this statutory restriction, as applied to their circumstances, would not be construed or applied by the FERC to prohibit the payment from retained earnings of dividends that are not excessive and are for lawful and legitimate business purposes.  In February 2012, LG&E and KU petitioned the FERC requesting authorization to pay dividends in the future based on retained earnings balances calculated without giving effect to the impact of purchase accounting adjustments for the acquisition of LKE by PPL.  In May 2012, FERC approved the petitions with the further condition that each utility may not pay dividends if such payment would cause its adjusted equity ratio to fall below 30% of total capitalization.  Accordingly, at December 31, 2012, net assets of $2.3 billion ($893 million for LG&E and $1.4 billion for KU) were restricted for the purposes of paying dividendstransferring funds to LKE,Talen Energy Corporation in the form of distributions, loans or advances.

6.  Acquisitions, Development and net assets of $2.3 billion ($917 million for LG&E and $1.4 billion for KU) were available for payment of dividends to LKE.  LG&E and KU believe they will not be required to change their current dividend practices as a result of the foregoing requirement.  In addition, under Virginia law, KU is prohibited from making loans to affiliates without the prior approval of the VSCC.  There are no comparable statutes under Kentucky law applicable to LG&E and KU, or under Pennsylvania law applicable to PPL Electric.  However, orders from the KPSC require LG&E and KU to obtain prior consent or approval before lending amounts to PPL.
Divestitures

(PPL and PPLTalen Energy Supply)

The PPL Montana Colstrip lease places certain restrictions on PPL Montana's ability to declare dividends.  At this time, PPL believes that these covenants will not limit PPL's or PPL Energy Supply's ability to operate as desired and will not affect their ability to meet any of their cash obligations.

(PPL)

WPD subsidiaries have financing arrangements that limit their ability to pay dividends.  However, PPL does not, at this time, expect that any of such limitations would significantly impact PPL's ability to meet its cash obligations.
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(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
                    
The following distributions and capital contributions occurred in 2012:
                  
    PPL Energy PPL          
    Supply Electric LKE LG&E KU
                    
Dividends/distributions paid to parent/member $ 787   $ 95  $ 155   $ 75  $ 100 
Capital contributions received from parent/member   563     150           

8.  Acquisitions, Development and Divestitures

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The Registrants from time to time evaluateevaluates opportunities for potential acquisitions, divestitures and development projects.  Development projects are periodically reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.  Any resulting transactions may impact future financial results.  

Acquisitions

MACH Gen

On November 2, 2015, Talen Energy completed the acquisition of the membership interests of MACH Gen for $603 million in cash consideration (based on estimated working capital). The final cash purchase price, after post-closing adjustments, was $600 million. The purchase price was funded by a borrowing under the Talen Energy Supply RCF and cash on hand. The Term Loan B and revolving credit facility of New MACH Gen remain outstanding following the completion of the transaction. See Note 5 for additional information. MACH Gen's total generating capacity is 2,344 MW (summer rating).
The MACH Gen acquisition was accounted for as a business combination, with the identifiable tangible and intangible assets and liabilities of MACH Gen, recorded at their estimated fair values on the acquisition date. The acquisition is consistent with management's strategy of business growth, fuel type diversity and replacing the assets being divested as part of the FERC approval of the RJS Power acquisition. The following table summarizes the allocation of the purchase price to the fair values of the major classes of assets and liabilities of MACH Gen.
Current assets (a) $31
Intangible assets 3
PP&E 1,275
Short-term debt (103)
Current liabilities (28)
Long-term debt (470)
Deferred income taxes (108)
Total purchase price $600

(a)
Includes gross contractual amounts of accounts receivable acquired of $9 million, which approximates fair value.

The purchase price allocation is considered by Talen Energy's management to be provisional due to pending finalization of valuations and could change materially in subsequent periods. Any changes to the provisional purchase price allocation during the measurement period that result in material changes to the consolidated financial results will be adjusted prospectively. The measurement period can extend up to a year from the date of acquisition. The items pending finalization include, but are not limited to, the valuation of PP&E, certain other assets and liabilities and deferred income taxes.

Actual operating revenues and net income of MACH Gen, since the November 2, 2015 acquisition, included in Talen Energy's results for the year ended December 31, 2015 were:
 Operating Revenues Net Income (Loss)
 $28
 $(9)

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RJS Power

On June 1, 2015, substantially contemporaneous with the spinoff by PPL to form Talen Energy, RJS Power was contributed by the Riverstone Holders to become a subsidiary of Talen Energy Supply in exchange for 44,974,658 shares of Talen Energy Corporation common stock. See Notes 1 and 3 for additional information on the spinoff and acquisition. In accordance with business combination accounting guidance, Talen Energy treated the combination with RJS Power as an acquisition and Talen Energy Supply is considered the acquirer of RJS Power. Accordingly, Talen Energy applied acquisition accounting to the assets and liabilities of RJS Power whereby the purchase price was allocated to the underlying tangible and intangible assets and liabilities based on their respective fair values as of June 1, 2015, with the remainder allocated to goodwill.

The total consideration for the acquisition was deemed to be $902 million based on the fair value of the Talen Energy Corporation common stock issued for the acquisition using the June 1, 2015 closing "when-issued" market price.

The following table summarizes the allocation of the purchase price to the fair values of the major classes of assets and liabilities of RJS, all of which represent non-cash activity excluded from the Statement of Cash Flows for the year ended December 31, 2015. The purchase price allocation is considered by Talen Energy's management to be final as of December 31, 2015.

Current assets (a) $168
Assets of discontinued operations (b) 375
PP&E 1,777
Other intangibles 46
Short-term debt (36)
Current liabilities (224)
Liabilities of discontinued operations (5)
Long-term debt (1,244)
Deferred income taxes (266)
Other noncurrent liabilities (c) (82)
Net identifiable assets acquired 509
Goodwill (d) 393
Net assets acquired $902

(a)
Includes gross contractual amount of the accounts receivable acquired of $41 million, which approximates fair value.
(b)
See Note 14 for information on impairment charges recorded during 2015 related to the Sapphire plants initial classification as assets held for sale and discontinued operations. See Note 1 for additional information on the subsequent reclassification to assets held and used.
(c)
Includes $33 million of "out-of-the-money" coal contracts that will be amortized over the life of the contracts terms as the coal is consumed.
(d)
The allocation above is as of the acquisition date of June 1, 2015. As further discussed in Note 16, goodwill was fully impaired during 2015, which included the goodwill recognized in the acquisition of RJS Power.

Various purchase accounting valuation adjustments were made during the third and fourth quarters affecting certain current assets and liabilities, PP&E, other intangibles and related deferred income taxes resulting in a $5 million reduction in goodwill. The statement of income effect of these adjustments recorded during the measurement period was insignificant.

Goodwill recorded as a result of the acquisition primarily reflected synergies expected to be achieved related to the spinoff and acquisition. The goodwill is not deductible for income tax purposes and was assigned to the East segment. See Note 16 for additional information related to the impairment of goodwill.

Actual operating revenues and net income of RJS, since the June 1 acquisition, included in Talen Energy's results for the year ended December 31, 2015 were:
 Operating Revenues Net Income (Loss) (a)
 $528
 $(74)

(a)Includes certain asset impairments and excludes the impact of the goodwill impairment recorded in 2015 subsequent to the acquisition. See Notes 14 and 16 for information on the impairments recorded.


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Pro Forma Information for RJS Power and MACH Gen Acquisitions

Pro forma information (unaudited) for Talen Energy for the year ended December 31, as if both the RJS Power and MACH Gen acquisitions had occurred January 1, 2014, is as follows:

  Operating Revenues  Income (Loss) After Tax from Continuing Operations
2015:    
Pro forma $5,109
 $(396)
Basic and diluted earnings per share (for Talen Energy Corporation)   (3.08)
2014:    
Pro forma 6,031
 345
Basic and diluted earnings per share (for Talen Energy Corporation)   2.68

The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the acquisitions taken place on the date indicated, or the future consolidated results of operations of Talen Energy. The pro forma financial information presented above has been derived from the historical consolidated financial statements of Talen Energy and MACH Gen and from the historical consolidated and combined financial statements of RJS Power.

The pro forma financial information presented above includes adjustments for (1) alignment of accounting policies, (2) incremental depreciation and amortization expense related to fair value adjustments to PP&E and identifiable intangible assets and liabilities, (3) incremental interest expense for outstanding borrowings to reflect the terms of the Talen Energy Supply RCF related to the RJS acquisition, (4) nonrecurring items (discussed below), (5) the tax effect of the above adjustments, and (6) the issuance of Talen Energy Corporation common stock in connection with the spinoff from PPL and the acquisition of RJS Power. The pro forma financial information presented includes the impact of impairments recorded during the third and fourth quarters of 2015. See Notes 14 and 16 for information on PPL Energy Supply's 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, which was presented as discontinued operations by PPL Energy Supply, and the sales of businesses in 2011 and prior years that were presented as discontinued operations by PPL, PPL Energy Supply and LKE.  See Note 10 for information on PPL's and PPL Energy Supply's 2012 Ironwood Acquisition and PPL's 2011 acquisition of WPD Midlands and 2010 acquisition of LKE.impairments recorded.

(PPL, LKE, LG&ENonrecurring acquisition, integration and KU)other costs directly related to the acquisitions of $20 million were incurred during 2015 and recorded in "Operation and maintenance" on the Statements of Income. Adjustments were made in the calculation of pro forma amounts to remove the effect of these nonrecurring items and related income taxes. The pro forma financial information does not include adjustments for potential future cost savings for either acquisition.

AcquisitionDivestitures

Terminated Bluegrass CTs AcquisitionTalen Renewable Energy

In November 2015, Talen Energy completed the sale of Talen Renewable Energy for $116 million in cash and recorded a pre-tax gain on the sale of $10 million in the East segment, which is reflected in "Operation and maintenance" on the Statement of Income.

Announced Divestitures

Ironwood, Holtwood, Lake Wallenpaupack and C.P. Crane Power Plants

In September 2011, LG&E and KUOctober 2015, Holtwood, LLC, a wholly owned, indirect subsidiary of Talen Energy, entered into an asset purchase agreement with Bluegrass Generation forto sell the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units,Holtwood and Lake Wallenpaupack hydroelectric facilities in Pennsylvania for a purchase price of $110$860 million, pending receiptsubject to customary purchase price adjustments. The facilities have a combined summer rating operating capacity of applicable regulatory approvals.  308 MW. The transaction is expected to close in March 2016, subject to customary closing conditions.

In May 2012,October 2015, Talen Generation entered into an agreement to sell Talen Ironwood Holdings, LLC, which through its subsidiaries owns and operates the KPSC issuedIronwood natural gas combined-cycle plant in Pennsylvania, for a purchase price of $657 million, subject to customary purchase price adjustments. In connection with the sale, in January 2016, Talen Energy repaid $41 million of indebtedness, plus a customary debt make-whole premium. The Ironwood unit has a summer rating operating capacity of 660 MW. The sale transaction closed in February 2016, with an estimated gain, net of transaction costs including

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the make-whole premium on the debt, of $159 million, which will be recorded to "Operating Income" on the Statement of Income in 2016. Proceeds from the sale of Ironwood were used to repay the majority of Talen Energy's short-term debt.

In October 2015, Raven Power Marketing LLC, a wholly owned, indirect subsidiary of Talen Energy, entered into an agreement to sell C.P. Crane LLC, which owns and operates the C.P. Crane coal-fired power plant in Maryland. The C.P. Crane plant has a summer rating operating capacity of 402 MW. The transaction closed in February 2016. The transaction is not expected to have a significant impact on Talen Energy's financial condition or results of operations. See Notes 14 and 16 for information on impairments recorded in 2015 for this plant.

The sales are part of the requirement to divest certain PJM assets to satisfy a December 2014 FERC order approving the requestcombination with RJS Power. See Note 1 for information on the FERC order.

At December 31, 2015, the major component of assets held for sale related to purchase the Bluegrass CTs.  sale of these businesses was primarily $936 million of PP&E which was included in the East segment. Talen Ironwood Holdings, LLC is considered an individually significant component whose pretax income (loss) attributable to Talen Energy for 2015, 2014, and 2013 was $73 million, $67 million, and $(22) million.

Discontinued Operations

Talen Montana Hydro Sale

In November 2011, LG&E2014, Talen Montana completed the sale to NorthWestern Corporation of 633 MW of hydroelectric generating facilities located in Montana for approximately $900 million in cash.  The sale included 11 hydroelectric power facilities and KU filed an application withrelated assets.

Following are the FERC undercomponents of discontinued operations in the Federal Power Act requesting approvalStatement of Income for the years ended December 31.    
  2014 2013
Operating revenues $117
 $139
Gain on the sale (pre-tax) 306
 —
Interest expense (a) 9
 12
Income (loss) before income taxes 332
 49
Income (Loss) from Discontinued Operations (net of income taxes) 223
 32

(a)Represents allocated interest expense based upon the discontinued operations share of the net assets of Talen Energy.  

Other

To facilitate the sale of the Montana hydroelectric generating facilities discussed above, Talen Montana terminated, in December 2013, its operating lease arrangement related to purchasepartial interests in Units 1, 2 and 3 of the Bluegrass CTs.  In May 2012,Colstrip coal-fired generating facility and acquired those interests, collectively, for $271 million. At lease termination, the FERC issued an order conditionally authorizingexisting lease-related assets on the balance sheet consisting primarily of prepaid rent and leasehold improvements were written off and the acquired Colstrip assets were recorded at fair value as of the acquisition date. Talen Energy recorded a charge of $697 million ($413 million after-tax) for the termination of the Bluegrass CTs, subject to approval bylease included in "Loss on lease termination" on the FERC2013 Statements of satisfactory mitigation measures to address market-power concerns.  After a reviewIncome. The $271 million payment is reflected in "Cash Flows from Operating Activities" on the 2013 Statement of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable.  In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.Cash Flow.

Development

Cane Run Unit 7 Construction

In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7.  In May 2012, the KPSC issued an order approving the request.  LG&E will own a 22% undivided interest, and KU will own a 78% undivided interest in the new generating unit.  A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate proceedings.  LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015.  The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.

In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring five older coal-fired electric generating units at the Cane Run and Green River plants, which have a combined summer capacity rating of 726 MW.  In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.
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Future Capacity Needs

In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs.  As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.  

(PPL and PPL Energy Supply)

Hydroelectric Expansion Projects

In 2009, in light of the availability of tax incentives and potential federal loan guarantees for renewable projects contained in the Economic Stimulus Package, PPL Energy Supply filed an application with the FERC to expand capacity at its Holtwood hydroelectric plant, which the FERC approved.  The project's expected cost is $443 million.  Construction continues on the project, with commercial operations scheduled to begin in 2013.  At December 31, 2012, expected remaining expenditures are $84 million.

In 2009, PPL Montana received FERC approval for its request to redevelop the Rainbow hydroelectric facility at Great Falls, Montana.  The project's expected cost is $209 million.  Commercial operations is scheduled to begin in 2013.  At December 31, 2012, expected remaining expenditures were insignificant.

PPL Energy Supply believes that it is qualified for either investment tax credits or Treasury grants for the projects at the Holtwood and Rainbow facilities.  PPL Energy Supply has recognized investment tax credits and continues to evaluate whether to seek Treasury grants in lieu of the credits.  During 2012, 2011 and 2010, PPL Energy Supply recorded deferred investment tax credits of $40 million, $52 million and $52 million.  PPL Energy Supply anticipates recognizing an additional $23 million in investment tax credits for tax year 2013.  These credits reduce PPL Energy Supply's tax liability and will be amortized over the life of the related assets.

Bell Bend COLA

In 2008, a PPLTalen Energy Supply subsidiary, PPL Bell Bend, LLC (PPL Bell(Bell Bend) submitted a COLA to the NRC for the proposed Bell Bend nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna plant.

Also in 2008, the COLA was formally docketed and accepted for review by the NRC.  PPL Bell Bend continues to respond to questions from the NRC regarding technical and site specific information provided in the initial COLA and subsequent amendments.  PPL Bell Bend does not expect to complete the COLA review process with the NRC prior to 2015.

In 2008, PPL Bell Bend submitted Parts I and II of an application for a federal loan guarantee for Bell Bend to the DOE. TheIn February 2014, the DOE is expected inannounced the first half of 2013 to finalize the first nuclear loan guarantee for a nuclear project in Georgia. EightAlthough eight of the ten applicants that submitted Part II applications remain active in the DOE program; however,program, the DOE has stated that the $18.5 billion currently appropriated to support new nuclear projects would not likely be enough for more than three projects. PPL Bell Bend submits quarterly application updates for Bell Bend to the DOE to remain active in the loan guarantee application process.

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The NRC continues to review the COLA. Bell Bend does not expect to complete the COLA review process with the NRC prior to 2018. Bell Bend has made no decision to proceed with construction of Bell Bend and expects that such decision will not be made for several years given the anticipated lengthy NRC license approval process. Additionally, PPL Bell Bend does not expect to proceed with construction absent favorable economics, a joint arrangement with other interested parties and a federal loan guarantee or other acceptable financing. PPL Bell Bend is currently authorized by Talen Energy Corporation's Board of Directors to spend up to $205$256 million through 2015 on the COLA and other permitting costs necessary for construction, which is expected to be sufficient to fund the project through receipt of the license.construction. At December 31, 20122015 and 2011, $1542014, $201 million and $131$188 million of costs, which includes capitalized interest, associated with the licensing application were capitalized and are included on the Balance Sheets in noncurrent "Other intangibles." PPLTalen Energy continues to support the Bell Bend believes thatlicensing project with a near term focus on obtaining the estimated fair valuefinal environmental impact statement. Talen Energy placed the NRC safety review (which supports issuance of their final safety evaluation report, the other key element of the COLA currently exceedsCOLA) on hold in 2014, due to a lack of progress by the costs expectedreactor vendor with respect to its NRC design certification process, which is a prerequisite to the COLA.

Brunner Island Co-firing Project

Talen Energy is in the process of making modifications to its Brunner Island coal-fired generating facility to be capitalizedable to co-fire using natural gas to better position the plant for the licensing application.

Regional Transmission Line Expansion Plan (PPLlow gas price environments. Construction is under way and PPL Electric)

Susquehanna-Roseland

In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid.  PJM determined that the line was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system.  PJM directed PPL Electric to construct the portion of
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the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.

On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review.  On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation, and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint.  PPL Electric has intervened in the lawsuit.  The chosen route had previously been approved by the PUC and the New Jersey Board of Public Utilities.

On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.

Construction activities have begun on portions of the 101-mile route in Pennsylvania.  The line is expected to be completed beforeby the peak summer demand periodend of 2015.2016. The project is expected to cost $118 million. At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.

PPL2015 and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to the scheduled in-service date for the new line.

Northeast/Pocono

In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities).  The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project.  The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive.  The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit with the FERC in March 2013.  PPL Electric expects the project to be completed in 2017.  At December 31, 2012, PPL Electric estimates the total project costs to be approximately $2002014, $23 million with approximately $190 million qualifying for the CWIP incentive.

9.  Discontinued Operations

(PPL and PPL Energy Supply)

Sale of Certain Non-core Generation Facilities

In 2011, PPL Energy Supply subsidiaries completed the sale of their ownership interests in certain non-core generation facilities, which were included in the Supply segment, for $381 million.  The transaction included the natural gas-fired facilities in Wallingford, Connecticut and University Park, Illinois and an equity interest in Safe Harbor Water Power Corporation, which owns a hydroelectric facility in Conestoga, Pennsylvania.

These non-core generation facilities met the held for sale criteria in the third quarter of 2010.  As a result, a pre-tax impairment charge of $96 million ($58 million after tax) was recorded and $5 million ($4 million after tax) of allocated goodwill was written off.  These chargescosts, which include capitalized interest, associated with the project were capitalized and are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2010 Statements of Income.

Following are the components of Discontinued Operations"Construction work in the Statements of Income.

    2011   2010 
          
Operating revenues    $ 19  $ 113 
Operating expenses (a)      11    156 
Operating income (loss)      8    (43)
Other income (expense) - net         2 
Interest expense (b)      3    11 
Income (loss) before income taxes      5    (52)
Income tax expense (benefit)      3    (18)
Income (Loss) from Discontinued Operations    $ 2  $ (34)
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(a)
2010 includes the impairments to the carrying value of the non-core generation facilities and the write-off of allocated goodwill.
(b)Represents allocated interest expense based upon debt attributable to the generation facilities sold.          

Sale of Long Island Generation Business

In 2010, PPL Energy Supply subsidiaries completed the sale of the Long Island generation business, which was included in the Supply segment.  Proceeds from the sale approximated $124 million.  There was no significant impact on earnings in 2010 from the operation of this business or as a result of the sale.

Sale of Maine Hydroelectric Generation Business

In 2010, a PPL Energy Supply subsidiary completed the sale of its Maine hydroelectric generation business, which was included in the Supply segment.  The business included eight hydroelectric facilities as well as a 50% equity interest in another hydroelectric facility.  The majority of the business was sold in 2009.  The remaining three hydroelectric facilities were sold in 2010 for $24 million, and also resulted in the receipt of an additional $14 million in contingent consideration in connection with the 2009 sale.  As a result of the consideration received in 2010, PPL Energy Supply recorded a gain of $25 million ($15 million after tax), reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2010 Statement of Income.

Distribution of Membership Interest in PPL Global to Parent(PPL Energy Supply)

In January 2011, PPL Energy Supply distributed its entire membership interest in PPL Global, which represented the entire U.K. Regulated segment, to PPL Energy Supply's parent, PPL Energy Funding.  The distribution was made based on the book value of the assets and liabilities of PPL Global with financial effect as of January 1, 2011, and no gains or losses were recognized on the distribution.  The purpose of the distribution was to better align PPL's organizational structure with the manner in which it manages these businesses, separating the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business.  Following the distribution, PPL Energy Supply operates in a single reportable segment, and through its subsidiaries is primarily engaged in the generation and marketing of power, primarily in the northeastern and northwestern U.S.

Following are the components of Discontinued Operations in the Statement of Income.

2010 
Operating revenues$ 761 
Operating expenses 368 
Operating income 393 
Other income (expense) - net 4 
Interest expense (a) 135 
Income before income taxes 262 
Income tax expense 1 
Income (Loss) from Discontinued Operations$ 261 

(a)No interest was allocated, as PPL Global was sufficiently capitalized.

The amount of cash and cash equivalents of PPL Global at the time of the distribution was reflected as a financing activity in the 2011 Statement of Cash Flows.

WKE

(PPL and LKE)

WKE had a 25-year lease for and operated generating facilities of BREC, and a coal-fired generating facility owned by the City of Henderson, Kentucky.  WKE terminated the lease in 2009 prior to PPL acquiring LKE.  See Note 15 for additional information related to the termination of the lease.  In 2012, an adjustment was made to the liability for certain WKE indemnifications, which is reflected in Discontinued Operations.  See "Guarantees and Other Assurances" in Note 15 for additional information on the adjustment and related indemnification.  The results of operations for the 2012, 2011 and 2010 periods were not significant.
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10.  Business Acquisitions

Ironwood Acquisition(PPL and PPL Energy Supply)

On April 13, 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of all of the equity interests of two subsidiaries of The AES Corporation, AES Ironwood, L.L.C. (subsequently renamed PPL Ironwood, LLC) and AES Prescott, L.L.C. (subsequently renamed PPL Prescott, LLC), which own and operate, respectively, the Ironwood Facility.  The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021.  The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM.

The fair value of the consideration paid for this acquisition was as follows.

Aggregate enterprise consideration$326 
Less: Fair value of long-term debt outstanding assumed through consolidation (a)258 
Plus: Restricted cash debt service reserves17 
Cash consideration paid for equity interests (including working capital adjustments)$85 

(a)The long-term debt assumed through consolidation consisted of $226 million aggregate principal amount of 8.857% senior secured bonds to be fully repaid by 2025, plus $8 million of debt service reserve loans, and a $24 million fair value adjustment.

Purchase Price Allocation

The following table summarizes the allocation of the purchase price to the fair value of the major classes of assets acquired and liabilities assumed through consolidation, and the effective settlement of the tolling agreement through consolidation.

PP&E$ 505 
Long-term debt (current and noncurrent) (a) (258)
Tolling agreement (b) (170)
Other net assets (a) 8 
Net identifiable assets acquired$ 85 

(a)Represents non-cash activity excluded from the 2012 Statement of Cash Flows.
(b)
Prior to the acquisition, PPL EnergyPlus had recorded primarily an intangible asset, which represented its rights to and the related accounting for the tolling agreement with PPL Ironwood, LLC.  On the acquisition date, PPL Ironwood, LLC recorded a liability, recognized at fair value, for its obligation to PPL EnergyPlus.  The tolling agreement assets of PPL EnergyPlus and the tolling agreement liability of PPL Ironwood, LLC eliminate in consolidation for PPL and PPL Energy Supply as a result of the acquisition, and therefore the agreement is considered effectively settled.  The difference between the tolling agreement assets and liability resulted in an insignificant loss on the effective settlement of the agreement.

During the fourth quarter of 2012, the purchase price allocation was finalized with no material adjustments made to the preliminary valuation.

Acquisition of WPD Midlands(PPL)

On April 1, 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of all of the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently renamed WPD Midlands), from subsidiaries of E.ON AG.  The consideration for the acquisition consisted of cash of $5.8 billion, including the repayment of $1.7 billion of affiliate indebtedness owed to subsidiaries of E.ON AG, and approximately $800 million of long-term debt assumed through consolidation.  WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England.  The acquisition increased the regulated portion of PPL's business and enhances rate-regulated growth opportunities as the regulated businesses make investments to improve infrastructure and customer reliability.  Further, since the service territories of WPD (South Wales), WPD (South West) and WPD Midlands are contiguous, cost savings, efficiencies and other benefits are achieved from the combined operations of these entities.

The fair value of the consideration paid for this acquisition was as follows (in billions).
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Aggregate enterprise consideration$ 6.6 
Less: Fair value of long-term debt outstanding assumed through consolidation 0.8 
Total cash consideration paid 5.8 
Less: Funds used to repay pre-acquisition affiliate indebtedness 1.7 
Cash consideration paid for Central Networks' outstanding ordinary share capital$ 4.1 

The total cash consideration paid was primarily funded by borrowings under the 2011 Bridge Facility on the date of acquisition.  Subsequently, PPL repaid those borrowings in 2011 using proceeds from the permanent financing, including issuances of common stock and 2011 Equity Units, as well as proceeds from the issuance of debt by PPL WEM, WPD (East Midlands) and WPD (West Midlands).  See Note 7 for additional information.

Purchase Price Allocation

The following table summarizes (in billions) the allocation of the purchase price to the fair value of the major classes of assets acquired and liabilities assumed.

Current assets (a)$ 0.2 
PP&E 4.9 
Intangible assets 0.1 
Other noncurrent assets 0.1 
Current liabilities (b) (0.4)
PPL WEM affiliate indebtedness (1.7)
Long-term debt (current and noncurrent) (b) (0.8)
Other noncurrent liabilities (b) (0.7)
Net identifiable assets acquired 1.7 
Goodwill 2.4 
Net assets acquired$ 4.1 

(a)
Includes gross contractual amount of the accounts receivable acquired of $122 million, which approximates fair value.
(b)Represents non-cash activity excluded from the 2011 Statement of Cash Flows.

The purchase price allocation resulted in goodwill of $2.4 billion that was assigned to the U.K. Regulated segment.  The goodwill is attributable to the expected continued growth of a rate-regulated business with a defined service area operating under a constructive regulatory framework, expected cost savings, efficiencies and other benefits resulting from a contiguous service area with WPD (South West) and WPD (South Wales), as well as the ability to leverage WPD (South West)'s and WPD (South Wales)'s existing management team's high level of performance in capital cost efficiency, system reliability and customer service.  The goodwill is not deductible for U.K. income tax purposes.

Separation Benefits - U.K. Regulated Segment

In connection with the 2011 acquisition, PPL completed a reorganization designed to transition WPD Midlands from a functional operating structure to a regional operating structure requiring a smaller combined support structure, reducing duplication and implementing more efficient procedures.  As a result of the reorganization, 729 employees of WPD Midlands have been terminated.

The separation benefits, before income taxes, associated with the reorganization are as follows.

Severance compensation$61 
Early retirement deficiency costs (ERDC) under applicable pension plans46 
Outplacement services1 
Total separation benefits$108 

In connection with the reorganization, WPD Midlands recorded $93 million of the total expected separation benefits in 2011, of which $48 million related to severance compensation and $45 million related to ERDC.  WPD Midlands recorded an additional $15 million of total separation benefits in 2012, of which $13 million related to severance compensation and $2 million related to ERDC.  The accrued severance compensation is reflected in "Other current liabilities" and the ERDC reduced "Other noncurrent assets"progress" on the Balance Sheets.  All separation benefits are included in "Other operation and maintenance" on the Statements of Income.
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The changes in the carrying amounts of accrued severance were as follows.

   2012   2011 
       
Accrued severance at beginning of period $ 21    
Severance compensation   13  $ 48 
Severance paid   (34)   (27)
Accrued severance at end of period $  $ 21 
In addition to the reorganization costs noted above, an additional $9 million was recorded in 2011 for ERDC payable under applicable pension plans and severance compensation for certain employees who separated from the WPD Midlands companies, but were not part of the reorganization.  These separation benefits are also included in "Other operation and maintenance" on the Statement of Income.

Other

WPD Midlands 2011 financial results included in PPL's Statement of Income and included in the U.K. Regulated segment were as follows.

Operating Revenues$ 790 
Net Income Attributable to PPL Shareowners 137 

Pro forma Information

The pro forma financial information, which includes LKE, discussed below, as if the acquisition had occurred January 1, 2009 and WPD Midlands as if the acquisition had occurred January 1, 2010, is as follows.

      2011  2010 
            
Operating Revenues - PPL consolidated pro forma (unaudited)      $ 13,140  $ 11,850 
Net Income Attributable to PPL Shareowners - PPL consolidated pro forma (unaudited)        1,800    1,462 

The pro forma financial information presented above has been derived from the historical consolidated financial statements of PPL and LKE, which was acquired on November 1, 2010, and from the historical combined financial statements of WPD Midlands, which was acquired on April 1, 2011.  Income (loss) from discontinued operations (net of income taxes), which was not significant for 2011 and was $(18) million for 2010, were excluded from the pro forma amounts above.

The pro forma financial information presented above includes adjustments to depreciation, net periodic pension costs, interest expense and the related income tax effects to reflect the impact of the acquisition.  The pre-tax nonrecurring credits (expenses) presented in the following table were directly attributable to the WPD Midlands and LKE acquisitions and adjustments were included in the calculation of pro forma operating revenue and net income to remove the effect of these nonrecurring items and the related income tax effects.

   Income Statement    
   Line Item     2011  2010 
                
WPD Midlands acquisition             
 2011 Bridge Facility costs (a)Interest Expense       $ (44)   
 Foreign currency loss on 2011 Bridge Facility (b)Other Income (Expense) - net         (57)   
 Net hedge gains associated with the 2011 Bridge Facility (c)Other Income (Expense) - net         55    
 Hedge ineffectiveness (d)Interest Expense         (12)   
 U.K. stamp duty tax (e)Other Income (Expense) - net         (21)   
 Separation benefits (f)Other operation and maintenance         (102)   
 Other acquisition-related adjustments(g)         (77)   
               
LKE acquisition             
 2010 Bridge Facility costs (h)Interest Expense          $ (80)
 Other acquisition-related adjustments (i)Other Income (Expense) - net            (31)

(a)
The 2011 Bridge Facility costs, primarily commitment and structuring fees, were incurred to establish a bridge facility for purposes of funding the WPD Midlands acquisition purchase price.
(b)The 2011 Bridge Facility was denominated in GBP.  The amount includes a $42 million foreign currency loss on PPL Capital Funding's repayment of its 2011 Bridge Facility borrowing and a $15 million foreign currency loss associated with proceeds received on the U.S. dollar-denominated senior notes issued by PPL WEM in April 2011 that were used to repay a portion of PPL WEM's borrowing under the 2011 Bridge Facility.
(c)The repayment of borrowings on the 2011 Bridge Facility was economically hedged to mitigate the effects of changes in foreign currency exchange rates with forward contracts to purchase GBP, which resulted in net hedge gains.
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(d)The hedge ineffectiveness includes a combination of ineffectiveness associated with closed out interest rate swaps and a charge recorded as a result of certain interest rate swaps failing hedge effectiveness testing, both associated with the acquisition financing.
(e)The U.K. stamp duty tax represents a tax on the transfer of ownership of property in the U.K. incurred in connection with the acquisition.
(f)See "Separation Benefits - U.K. Regulated Segment" above.
(g)Primarily includes acquisition-related advisory, accounting and legal fees recorded in "Other Income (Expense) - net" and contract termination costs, rebranding costs and relocation costs recorded in "Other operation and maintenance."  
(h)Primarily commitment and structuring fees, incurred to establish a bridge facility for purposes of funding the acquisition purchase price.
(i)Primarily includes acquisition-related advisory, accounting and legal fees.

Acquisition of LKE

(PPL)

On November 1, 2010, PPL completed the acquisition of all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG.  Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC (LKE).  LKE is a holding company with regulated utility operations conducted through its subsidiaries, LG&E and KU.  The acquisition reapportions the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business, strengthens PPL's credit profile and enhances rate-regulated growth opportunities as the regulated businesses make investments to improve infrastructure and customer reliability.

The fair value of the consideration paid for this acquisition was as follows (in billions).

Aggregate enterprise consideration$ 7.6 
Less: Fair value of assumed long-term debt outstanding, net 0.8 
Total cash consideration paid 6.8 
Less: Funds used to repay pre-acquisition affiliate indebtedness 4.3 
Cash consideration paid for E.ON U.S. LLC equity interests$ 2.5 

The total cash consideration paid, including repayment of affiliate indebtedness, was funded by PPL's June 2010 issuance of $3.6 billion of common stock and 2010 Equity Units that provided proceeds totaling $3.5 billion, net of underwriting discounts, $3.2 billion of borrowings under an existing credit facility in October 2010, $249 million of proceeds from the monetization of certain full-requirement sales contracts in July 2010 and cash on hand.  See Note 7 for additional information on the issuance of common stock and 2010 Equity Units and the October 2010 borrowing under PPL Energy Supply's syndicated credit facility that provided interim financing to partially fund the acquisition.  See Note 19 for additional information on the monetization of certain full-requirement sales contracts.

Purchase Price Allocation

The following table summarizes (in billions) the allocation of the purchase price to the fair value of the major classes of assets acquired and liabilities assumed.

Current assets (a)$ 0.9 
PP&E 7.5 
Other intangibles (current and noncurrent) 0.4 
Regulatory and other noncurrent assets 0.7 
Current liabilities, excluding current portion of long-term debt (b) (0.5)
PPL affiliate indebtedness (c) (4.3)
Long-term debt (current and noncurrent) (b) (0.9)
Other noncurrent liabilities (b) (2.3)
Net identifiable assets acquired 1.5 
Goodwill 1.0 
Net assets acquired$ 2.5 

(a)
Includes gross contractual amount of the accounts receivable acquired of $186 million.  PPL expected $11 million to be uncollectible; however, credit risk is mitigated since uncollectible accounts are a component of customer rates.
(b)Represents non-cash activity excluded from the 2010 Statement of Cash Flows.
(c)Includes $1.6 billion designated as a capital contribution to LKE.

For purposes of goodwill impairment testing, the $996 million of goodwill was assigned to the PPL reportable segments expected to benefit from the acquisition.  Both the Kentucky Regulated and the Supply segments are expected to benefit and the assignment of goodwill was $662 million to the Kentucky Regulated segment and $334 million to the Supply segment.  The goodwill at the Kentucky Regulated segment reflects the value paid for the expected continued growth of a rate-regulated business located in a defined service area with a constructive regulatory environment, the ability of LKE to leverage its assembled workforce to take advantage of those growth opportunities and the attractiveness of stable, growing cash flows.  Although no other assets or liabilities from the acquisition were assigned to the Supply segment, the Supply
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segment obtained a synergistic benefit attributed to the overall de-risking of the PPL portfolio, which enhanced PPL Energy Supply's credit profile, thereby increasing the value of the Supply segment.  This increase in value resulted in the assignment of goodwill to the Supply segment.  The goodwill is not deductible for income tax purposes.  As such, no deferred taxes were recorded related to goodwill.

See Note 9 and the "Guarantees and Other Assurances" section of Note 15 for additional information on certain indemnifications provided by LKE, the most significant of which relates to the discontinued operations of WKE.

The 2010 LKE financial results included in PPL's Statement of Income and included in the Kentucky Regulated segment were as follows.

     Net Income 
     (Loss) 
     Attributable 
  Operating to PPL 
  Revenues Shareowners 
        
From November 1, 2010 - December 31, 2010 $ 493  $ 47  

(PPL, PPL Energy Supply, LKE, LG&E and KU)

In November 2010, LKE, LG&E and KU issued debt totaling $2.9 billion, of which LKE used $100 million to return capital to PPL.  The majority of these proceeds, together with a borrowing by LG&E under its available credit facilities, were used to repay borrowings from a PPL Energy Supply subsidiary.  Such borrowings were incurred to permit LKE to repay certain indebtedness owed to affiliates of E.ON AG upon the closing of the acquisition.  In November 2010, PPL Energy Supply used the above-referenced amounts received from LKE, together with other cash on hand, to repay approximately $3.0 billion of its October 2010 borrowing under existing credit facilities.

(PPL and PPL Energy Supply)

To ensure adequate funds were available for the acquisition, in July 2010, PPL Energy Supply monetized certain full-requirement sales contracts that resulted in cash proceeds of $249 million.  See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 for additional information.  Additionally, PPL Energy Supply received proceeds in 2011 from the sale of certain non-core generation facilities, which were used to repay the short-term borrowings drawn on existing credit facilities.  See "Sale of Certain Non-core Generation Facilities" in Note 9 for additional information.

As a result of the monetization of these full-requirement sales contracts, coupled with the expected net proceeds from the then-anticipated sale of these non-core generation facilities, debt that had been planned to be issued by PPL Energy Supply in late 2010 was no longer needed.  Therefore, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued.  Net gains (losses) of $(29) million, or $(19) million after tax, were reclassified from AOCI to "Other Income (Expense) - net" on PPL's 2010 Statement of Income.

(LKE, LG&E and KU)

On November 1, 2010, PPL completed its acquisition of LKE and its subsidiaries.  The push-down basis of accounting was used to record the fair value adjustments of assets and liabilities on LKE at the acquisition date.  PPL paid cash consideration for the equity interests in LKE and its subsidiaries of $2,493 million and provided a capital contribution on November 1, 2010, of $1,565 million; included within this was the consideration paid of $1,702 million for LG&E and $2,656 million for KU.  The allocation of the purchase price was based on the fair value of assets acquired and liabilities assumed.

The push-down accounting for the fair value of assets acquired and liabilities assumed was as follows (in millions).
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   LKE  LG&E  KU
          
Current assets $ 969  $ 503  $ 341 
Investments   31    1    30 
PP&E   7,469    2,935    4,531 
Other intangibles (current and noncurrent)   427    226    201 
Regulatory and other noncurrent assets   689    416    274 
Current liabilities, excluding current portion of long-term debt   (516)   (420)   (367)
PPL affiliate indebtedness   (4,349)   (485)   (1,331)
Long-term debt (current and noncurrent)   (934)   (580)   (352)
Other noncurrent liabilities   (2,289)   (1,283)   (1,278)
Net identifiable assets acquired   1,497    1,313    2,049 
Goodwill   996    389    607 
Net assets acquired   2,493    1,702    2,656 
Capital Contribution on November 1, 2010, to replace affiliate indebtedness   1,565       
Beginning equity balance on November 1, 2010 $ 4,058  $ 1,702  $ 2,656 

Goodwill represents value paid for the rate regulated businesses of LG&E and KU, which are located in a defined service area with a constructive regulatory environment, which provides for future investment, earnings and cash flow growth, as well as the talented and experienced workforce.  LG&E's and KU's franchise values are being attributed to the going concern value of the business, and thus were recorded as goodwill rather than a separately identifiable intangible asset.  None of the goodwill recognized is deductible for income tax purposes or included in customer rates.

Adjustments to LKE's, LG&E's and KU's assets and liabilities that contributed to goodwill are as follows:

The fair value adjustment on the EEI investment was calculated using the discounted cash flow valuation method.  The result was an increase in KU's value of the investment in EEI; the fair value of EEI was calculated to be $30 million and a fair value adjustment of $18 million was recorded on KU.  The fair value adjustment to EEI was being amortized over the expected remaining useful life of plant and equipment at EEI, which was estimated to be over 20 years.  During the fourth quarter of 2012, KU recorded an impairment in EEI.  See Notes 1 and 18 for additional information.

The pollution control bonds, excluding the reacquired bonds, had a fair value adjustment of $7 million for LG&E and $1 million for KU.  All variable bonds were valued at par while the fixed rate bonds were valued with a yield curve based on average credit spreads for similar bonds.

As a result of the purchase accounting associated with the acquisition, the following items had a fair value adjustment but no effect on goodwill as the offset was either a regulatory asset or liability.  The regulatory asset or liability has been recorded to eliminate any ratemaking impact of the fair value adjustments:

·The value of OVEC was determined to be $126 million based upon an announced transaction by another owner.  LG&E and KU's combined investment in OVEC was not significant and the power purchase agreement was valued at $87 million for LG&E and $39 million for KU.  An intangible asset was recorded with the offset to regulatory liability and is amortized using the units of production method until March 2026, the expiration date of the agreement at the date of the acquisition.

·LG&E and KU each recorded an emission allowance intangible asset and a regulatory liability as the result of adjusting the fair value of the emission allowances at LG&E and KU.  The emission allowance intangible of $8 million at LG&E and $9 million at KU represents allocated and purchased sulfur dioxide and nitrogen oxide emission allowances that were unused as of the valuation date or allocated for use in future years.  LG&E and KU had previously recorded emission allowances as other materials and supplies.  To conform to PPL's accounting policy all emission allowances are now recorded as intangible assets.  The emission allowance intangible asset is amortized as the emission allowances are consumed, which is expected to occur through 2040.

·Coal contract intangible assets were recorded at LG&E for $124 million and at KU for $145 million as well as a non-current liability of $11 million for LG&E and $22 million for KU on the Balance Sheets.  An offsetting regulatory asset was recorded for those contracts with unfavorable terms relative to market.  An offsetting regulatory liability was recorded for those contracts that had favorable terms relative to market.  All coal contracts held by LG&E and KU, wherein it had entered into arrangements to buy amounts of coal at fixed prices from counterparties at a future date, were fair valued.  The intangible assets and other liabilities, as well as the regulatory assets and liabilities, are being amortized over the same terms as the related contracts, which expire through 2016.

308
·Adjustments on November 1, 2010 were made to record LKE pension assets at fair value, remeasure its pension and postretirement benefit obligations at current discount rates and eliminate accumulated other comprehensive income (loss).  An increase of $4 million in the liability balances of LG&E and KU was recorded, due to the lowering of the discount rate; this was credited to their respective pension and postretirement liability balances with offsetting adjustments made to the related regulatory assets and liabilities.

The fair value of intangible assets and liabilities (e.g. contracts that have favorable or unfavorable terms relative to market), including coal contracts and power purchase agreements, as well as emission allowances, have been reflected on the Balance Sheets with offsetting regulatory assets or liabilities.  Prior to the acquisition, LG&E and KU recovered the cost of the coal contracts, power purchases and emission allowances and this rate treatment will continue after the acquisition.  As a result, management believes the regulatory assets and liabilities created to offset the fair value adjustments meet the recognition criteria established by existing accounting guidance and eliminate any ratemaking impact of the fair value adjustments.  LG&E's and KU's customer rates will continue to reflect these items (e.g. coal, purchased power, emission allowances) at their original contracted prices.

LG&E and KU also considered whether a separate fair value should be assigned to LG&E's and KU's rights to operate within its various electric and natural gas distribution service areas but concluded that these rights only provided the opportunity to earn a regulated return and barriers to market entry, which in management's judgment is not considered a separately identifiable intangible asset under applicable accounting guidance; rather, it is considered going-concern value, or goodwill.

Kentucky Acquisition Commitments

(PPL, LKE, LG&E and KU)

In connection with the September 2010 approval of PPL's acquisition of LKE, LG&E and KU agreed to implement the Acquisition Savings Sharing Deferral (ASSD) methodology whereby LG&E's and KU's adjusted jurisdictional revenues, expenses, and net operating income are calculated each year.  If LG&E's or KU's actual earned rate of return on common equity exceeds 10.75%, half of the excess amount will be deferred as a regulatory liability and ultimately returned to customers.  The first ASSD filing with the KPSC was made on March 30, 2012 based on the 2011 calendar year.  On July 2, 2012, the KPSC issued an order approving the calculations contained in the 2011 ASSD filing and determined that such calculations produced no deferral amounts for the purpose of establishing regulatory liabilities and are proper and in accordance with the settlement agreement.  The ASSD methodology for each of LG&E's and KU's utility operations terminated on January 1, 2013, when new rates went into effect.  Therefore, no further ASSD filings will be made.

11.  Leases

Lessee Transactions

(PPL, LKE, LG&E and KU)

E.W. Brown Combustion Turbines

LG&E and KU are participants in a sale-leaseback transaction involving two combustion turbines at the E.W. Brown generating plant.  In December 1999, after selling their interests in the combustion turbines, LG&E and KU entered into an 18-year lease of the turbines.  LG&E and KU provided funds to fully defease the lease including the repurchase price and have the right to exercise an early purchase option contained in the lease after 15.5 years, which will occur in 2015.  The financial statement treatment of this transaction is the same as if LG&E and KU had retained their ownership interest.  Since the lease was defeased, there are no remaining minimum lease payments and all related PP&E is reflected on the Balance Sheets.  See Note 14 for the balances included on the Balance Sheets related to this transaction.  Depreciation expense was insignificant for all periods presented.

Upon a default under the lease, LG&E and KU are obligated to pay to the lessor their share of certain amounts.  Primary events of default include loss or destruction of the combustion turbines, failure to insure or maintain the combustion turbines and unwinding of the transaction due to governmental actions.  No events of default currently exist with respect to the lease.  Upon any termination of the lease, whether by default or expiration of its term, title to the combustion turbines reverts to LG&E and KU.  The maximum aggregate amount at December 31, 2012 that could be required to be paid by LKE is $5 million, by LG&E is $2 million and by KU is $3 million.  LKE has guaranteed the payment of these potential default payments of LG&E and KU.
309
(PPL and PPL Energy Supply)

Colstrip Generating Plant

In July 2000, PPL Montana sold its interest in the Colstrip generating plants to owner lessors who lease back to PPL Montana, under four 36-year non-cancelable leases, a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3.  This transaction is accounted for as a sale-leaseback and classified as an operating lease.  PPL Montana is responsible for its share of the operating expenses associated with its leasehold interests.  See Note 14 for information on the sharing agreement for Colstrip Units 3 and 4.  PPL Montana currently amortizes material leasehold improvements over no more than the remaining life of the original leases; however, the leases provide two renewal options based on the economic useful life of the generation assets.  The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assets and declare dividends and require PPL Montana to maintain certain financial ratios related to cash flow and net worth.  There are no residual value guarantees in these leases.  However, upon an event of default or an event of loss, PPL Montana could be required to pay a termination value of amounts sufficient to allow the lessor to repay amounts owing on the lessor notes and make the lessor whole for its equity investment and anticipated return on investment.  The events of default include payment defaults, breaches of representations or covenants, acceleration of other indebtedness of PPL Montana, change in control of PPL Montana and certain bankruptcy events.  The termination value was estimated to be $301 million at December 31, 2012.

Kerr Dam

Under the Kerr Hydroelectric Project No. 5 joint operating license issued by the FERC, PPL Montana is responsible to make payments to the Confederated Salish and Kootenai Tribes of the Flathead Nation for the use of certain of their tribal lands in connection with the operation of Kerr Dam.  This payment arrangement, subject to escalation based upon inflation, extends until the end of the license term in 2035.  Between 2015 and 2025, the tribes have the option to purchase, hold and operate the project, at a conveyance price to be determined in accordance with the provisions in the FERC license.  Exercise of the option by the tribes would result in the termination of this payment arrangement obligation for PPL Montana.  The payment arrangement has been treated as an operating lease for accounting purposes.  In February 2013, the parties to the license submitted the issue of the appropriate amount of the conveyance price to arbitration.

(PPL, PPL Energy Supply, LKE, LG&E and KU)

Other7. Leases

PPLTalen Energy and its subsidiaries have entered into various agreements for the lease of office space, vehicles, land, gas storage and other equipment. At December 31, 2015, Talen Energy's most significant lease, which expires in 2018, relates to its corporate headquarters.

Rent - Operating Leases

Rent expense for the years ended December 31 for operating leases was as follows:
 2015 2014 2013
 $14
 $29
 $55

   2012   2011   2010 
          
PPL $116  $109  $90 
PPL Energy Supply  62   84   87 
Total future minimum rental payments for all operating leases are estimated to be:
2016 2017 2018 2019 2020 Thereafter Total
$19
 $18
 $8
 $5
 $5
 $26
 $81

8.  Stock-Based Compensation

  Successor  Predecessor
        Two Months  Ten Months
  Year Ended Year Ended  Ended  Ended
  December 31, December 31,  December 31,  October 31,
  2012  2011   2010   2010 
               
LKE $ 18  $ 18   $ 3   $ 14 
LG&E   7    7     1     5 
KU   10    10     2     8 
310
Total future minimum rental payments for all operating leases are estimated to be:
                
    PPL      
  PPL Energy Supply LKE LG&E KU
                
2013  $ 109  $ 76  $ 15  $ 5  $ 9 
2014    106    78    15    6    8 
2015    85    65    12    5    7 
2016    37    26    8    3    5 
2017    21    13    6    2    4 
Thereafter   149    104    34    14    18 
Total $ 507  $ 362  $ 90  $ 35  $ 51 
Stock Incentive Plan

12.  Stock-Based Compensation

(PPL, PPLTalen Energy Supply, PPL Electric and LKE)

In 2012, shareowners approvedCorporation grants share-based compensation to eligible participants under the PPL SIP.  This new equity plan replaces the PPL ICP and incorporates the following changes:

·  Eliminates the potential to pay dividend equivalents on stock options.

·  Eliminates the automatic lapse of restrictions on all equity awards in the event of a "potential" change in control and requires that a termination of employment occur in the event of a change in control before restrictions lapse.

·  Changes the treatment of outstanding stock options upon retirement to limit the exercise period to the earlier of the end of the term (ten years from grant) or five years after retirement.

To further align the executives' interests with those of PPL shareowners, this plan provides that each restricted stock unit entitles the executive to accrue additional restricted stock units equal to the amount of quarterly dividends paid on PPL stock.  These additional restricted stock units would be deferred and payable in shares of PPL common stock at the end of the restriction period.  Dividend equivalents on restricted stock unit awards prior to 2013 are currently paid in cash when dividends are declared by PPL.

Talen Energy Stock Incentive Plan (SIP). Under the ICP, SIP, and the ICPKE (together, the Plans), restricted shares of PPL commonTalen Energy Corporation stock, restricted stock units, performance units, stock options and stock optionsappreciation rights may be granted to officers, directors and other key employees. Additionally, Talen Energy Corporation will match shares of its common stock purchased by certain employees on the open market from June 1, 2015 through March 31, 2018 with grants of PPL, PPL Energy Supply, PPL Electric, LKE and other affiliated companies.restricted stock units, subject to certain restrictions (Matching Grants). Awards under the PlansSIP are made by the Compensation, Governance and Nominating Committee (CGNC) of the PPLTalen Energy Corporation Board of Directors in the case of the ICP and SIP, and by the PPL Corporate Leadership Council (CLC), in the case of the ICPKE.or its delegate.

The following table details the award limits under eachtotal number of the plans.

    Annual Grant Limit   Annual Grant Limit
    Total As % of   For Individual Participants -
  Total Plan Outstanding Annual Grant Performance Based Awards
  Award PPL Common Stock Limit For awards For awards
  Limit On First Day of Options denominated in denominated in
Plan (Shares) Each Calendar Year (Shares) shares (Shares) cash (in dollars)
            
ICP(a) 15,769,431  2% 3,000,000      
SIP 10,000,000    2,000,000  750,000  $15,000,000 
ICPKE 14,199,796  2% 3,000,000      

(a)Applicable to outstanding awards granted from January 27, 2006 to January 26, 2012.  During 2012, the total plan award limit was reached and the ICP was replaced by the SIP.

Any portion of these awards that has not been grantedshares which may be carried overissued under the plan is 5,630,000 and used in any subsequent year.  If any award lapses,the maximum number of shares for which stock options may be granted is forfeited or the rights of the participant terminate, the shares of PPL common stock underlying such an award are again available for grant.2,000,000. Shares delivered under the PlansSIP may be in the form of authorized and unissued PPLTalen Energy Corporation common stock or common stock held in treasury by PPL or PPL common stock purchased on the open market (including private purchases) in accordance with applicable securities laws.Talen Energy Corporation.

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Restricted Stock and Restricted Stock Units

Restricted shares of PPL common stock are outstanding shares with full voting and dividend rights.  Restricted stock awards are granted as a retention award for select key executives and vest when the recipient reaches a certain age or meets service or other criteria set forth in the executive's restricted stock award agreement.  The shares are subject to forfeiture or accelerated payout under plan provisions for termination, retirement, disability and death of employees.  Restricted shares vest fully, in certain situations, as defined by each of the Plans.

The Plans allow for the grant of restricted stock units.  Restricted stock units are awards based on the fair value of PPLa share of Talen Energy Corporation common stock on the date of grant. Actual PPLTalen Energy Corporation common shares will be issued upon completion of a vesting period of three years,

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aside from Matching Grants that generally three years.vest two years from the date of grant. Substantially all restricted stock unit awards are expected to vest.

The fair value of restricted stock and restricted stock units granted is recognized as compensation expense on a straight-line basis over the service period or through the date at which the employee reaches retirement eligibility.  The fair value of restricted stock and restricted stock units granted to retirement-eligible employees is recognized as compensation expense immediately upon the date of grant.  Recipients of restricted stock and restricted stock units may also be granted the right to receive dividend equivalents through the end of the restriction period or until the award is forfeited.period. Restricted stock and restricted stock units are subject to forfeiture or accelerated payout under the planpertinent award agreement provisions for termination, retirement, disability and death of employees. Restricted stock and restricted stock units vest fully, in certain situations, as defined by each ofin the Plans.

applicable award agreement. The total restricted stock units granted, nonvested and outstanding through December 31, 2015 was 265,849 and the weighted-average grant date fair value of restricted stock and restricted stock units granted was:per share was $18.74.

   2012  2011  2010 
           
PPL $ 28.35  $ 25.25  $ 28.93 
PPL Energy Supply   28.29    25.14    29.49 
PPL Electric   28.51    25.09    29.40 
LKE   28.34       26.31 
Stock Options

RestrictedStock options have been granted with an option exercise price per share not less than the fair value of Talen Energy Corporation's common stock and restricted stock unit activity for 2012 was:    

      Weighted-
      Average
    Restricted Grant Date Fair
    Shares/Units Value Per Share
PPL      
Nonvested, beginning of period   2,040,035  $ 27.03 
 Granted   1,487,556    28.35 
 Vested   (1,002,229)   27.23 
 Forfeited   (21,592)   27.69 
Nonvested, end of period   2,503,770    27.73 
        
PPL Energy Supply      
Nonvested, beginning of period   665,180  $ 27.30 
 Transferred   62,320    28.66 
 Granted   564,020    28.29 
 Vested   (219,124)   27.04 
 Forfeited   (11,710)   27.97 
Nonvested, end of period   1,060,686    27.95 
        
PPL Electric      
Nonvested, beginning of period   251,595  $ 27.10 
 Transferred   (54,460)   28.93 
 Granted   133,530    28.51 
 Vested   (61,995)   27.63 
 Forfeited   (7,442)   27.46 
Nonvested, end of period   261,228    27.30 
        
LKE      
Nonvested, beginning of period   145,210  $ 26.31 
 Granted   144,340    28.34 
 Vested   (149,910)   26.38 
Nonvested, end of period   139,640    28.34 

on the date of grant. Options become exercisable in equal installments over a three-year service period beginning one year after the date of grant, assuming the individual is still employed by Talen Energy or a subsidiary. The CGNC has discretion to accelerate the exercisability of the options. All options expire no later than ten years from the grant date. The options become exercisable immediately in certain situations, as defined by the pertinent award agreement. The fair value of options granted is recognized as compensation expense on a straight-line basis over the service period. Substantially all restricted stock and restricted stock unitoption awards are expected to vest. The total stock options granted, nonvested and outstanding through December 31, 2015 was 991,101 and the grant date fair value per share was $4.91. The weighted-average exercise price per share is $19.00 and the weighted-average remaining contractual term is 9.4 years. The stock options outstanding at December 31, 2015 are currently out of the money.
The fair value of each option granted is estimated using a Black-Scholes option-pricing model. Talen Energy uses a risk-free interest rate, expected option life and expected volatility to value its stock options. Talen Energy Corporation does not currently expect to pay dividends, therefore a dividend yield assumption is not used to value stock options. The risk-free interest rate reflects the yield for a U.S. Treasury Strip available on the date of grant with constant rate maturity approximating the option's expected life. Expected life was calculated using the simplified method described in SEC Staff Accounting Bulletin (SAB) 107/110 (updated by SAB 110). Expected volatility is derived from the historical volatility of a peer group selected by management as Talen Energy Corporation's common stock does not have a trading history.

The total fair value of restricted stock and restricted stock units vesting forassumptions used in the years ended December 31 was:     model were:
312
   2012  2011  2010 
           
PPL $ 27  $ 19  $ 15 
PPL Energy Supply   6    6    7 
PPL Electric   2    2    2 
LKE   4    1    
Risk-free interest rate2.05%
Expected option life6.00 years
Expected stock volatility21.55%

Performance Units

Performance units are intended to encourage and award future performance.  Performance units represent a target number of shares (Target Award) of PPL'sTalen Energy Corporation's common stock that the recipient would receive upon PPL'sTalen Energy Corporation's attainment of thean applicable performance goal. PerformanceFor awards granted in 2015, Talen Energy Corporation uses TSR, which is determined based on total shareowner returnTSR during a 3-yearthree-year performance period. At the end of the performance period, payout is determined by comparing PPL's performanceTalen Energy Corporation's TSR to the total shareowner returnTSR of thepeer group companies included in an index group, in the case of the 2010 and 2011 awards, the S&P 500 Electric Utilities Index, and in the case of the 2012 awards, the Philadelphia Electric Utilities Index.that Talen Energy Corporation has selected. Awards granted in 2010 are payable on a graduated basis, withinbased on thresholds that measure Talen Energy Corporation's performance relative to the following ranges:  if PPL's performance is at or above the 85th percentile of the indexpeer group the award iscompanies, on which each years' awards are measured. Awards can be paid atup to 200% of the Target Award; at the 50th percentile of the index group, thetarget award or forfeited with no payout if performance is paid at 100% of the Target Award; at the 40th percentile of the index group, the award is paid at 50% of the Target Award; and below the 40th percentile, no award is payable.  Awards granted in 2011 and 2012 are payable on a graduated basis similar to 2010, except that the 2011 awards provide for a minimum payment at 25% of the Target Award ifestablished performance falls below the 40th percentile of the index group, and in 2012 the minimum payment was eliminated, with no award payable if performance falls below the 25th percentile.  Dividends payable during the performance cycle accumulate and are converted into additional performance units and are payable in shares of PPL common stock upon completion of the performance period based on the determination of the CGNC of whether the performance goals have been achieved.threshold. Under the planpertinent award agreement provisions, performance units are subject to forfeiture upon termination of employment except for retirement,in the event of a disability or death of an employee, in which case the total performance units remain outstanding and are eligible for vesting through the conclusion of the performance period. The fair value of performance units granted is recognized as compensation expense on a straight-line basis over the 3-yearthree-year performance period. Performance units vest on a pro rata basis, in certain situations, as defined by each of the Plans.applicable award agreement.

The fair value of each performance unitunits granted was estimated using a Monte Carlo pricing model that considers stock beta, a risk-free interest rate,values market based performance conditions such as TSR. The model assumed an expected stock volatility and expected life.  The stock betaof 31.8% that was calculated comparingbased on the risk of the individual securities to the average risk of the companies in the index group.  The risk-free interest rate reflects the yieldhistorical volatility based on a U.S. Treasury bond commensurate with the expected life of the performance unit.  Volatility over the expected term of the performance unit is calculated using daily stock price observations for PPL and all companies in the indexchanges of peer group and is evaluated with consideration given to prior periods that may need to be excluded based on events not likely to recur that had impacted PPL and the companies in the index group.  PPL had used historical volatility to value itscompanies.

The total performance units in 2010.  Beginning in 2011, PPL began using a mix of historicgranted, nonvested and implied volatility in response tooutstanding through December 31, 2015 was 158,900 and the significant changes in its business model, moving from a primarily unregulated to a primarily regulated business model, as a result of the acquisitions of LKE and WPD Midlands.

The weighted-average assumptions used in the model were:   

    2012   2011   2010 
           
Risk-free interest rate  0.30%  1.00%  1.41%
Expected stock volatility  19.30%  23.40%  34.70%
Expected life  3 years  3 years  3 years

The weighted-average grant date fair value of performance units granted was:    was $21.17 per share.

   2012  2011  2010 
           
PPL $ 31.41  $ 29.67  $ 34.06 
PPL Energy Supply   31.40    29.68    34.16 
PPL Electric   31.37    29.57    33.54 
LKE   31.30    29.20    

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Performance unit activity for 2012 was:   

      Weighted-
      Average Grant
   Performance Date Fair Value
   Units Per Share
PPL      
Nonvested, beginning of period   398,609  $ 33.31 
 Granted   322,771    31.41 
 Forfeited   (127,177)   38.61 
Nonvested, end of period   594,203    31.14 
        
PPL Energy Supply      
Nonvested, beginning of period   75,067  $ 33.00 
 Transferred   12,719    34.15 
 Granted   71,572    31.40 
 Forfeited   (35,169)   38.90 
Nonvested, end of period   124,189    31.26 
        
PPL Electric      
Nonvested, beginning of period   32,808  $ 33.11 
 Transferred   (12,719)   34.15 
 Granted   16,234    31.37 
 Forfeited   (10,240)   34.17 
Nonvested, end of period   26,083    31.10 
        
LKE      
Nonvested, beginning of period   26,893  $ 29.20 
 Granted   55,857    31.30 
Nonvested, end of period   82,750    30.62 
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Stock OptionsDirectors Deferred Compensation Plan

Under the Plans,Talen Energy Corporation Directors Deferred Compensation Plan, or DDCP, stock options may beunits are granted to eligible directors of Talen Energy Corporation in connection with an option exercise price per share not less thantheir retainers for service on Talen Energy Corporation’s board of directors and its committees. Stock units are based on the fair market value of PPL'sa share of Talen Energy Corporation’s common stock on the date of grant. Options outstanding atThe total number of stock units granted under the DDCP through December 31, 2012, become exercisable in equal installments over a three-year service period beginning one year after the date of grant, assuming the individual is still employed by PPL or a subsidiary.  The CGNC and CLC have discretion to accelerate the exercisability of the options, except that the exercisability of an option issued under the ICP may not be accelerated unless the individual remains employed by PPL or a subsidiary for one year from the date of grant.  All options expire no later than ten years from the grant date.  The options become exercisable immediately in certain situations, as defined by each of the Plans.  The fair value of options granted is recognized as compensation expense on a straight-line basis over the service period or through the date at which the employee reaches retirement eligibility.  The fair value of options granted to retirement-eligible employees is recognized as compensation expense immediately upon the date of grant.

The fair value of each option granted is estimated using a Black-Scholes option-pricing model.  PPL uses a risk-free interest rate, expected option life, expected volatility and dividend yield to value its stock options.  The risk-free interest rate reflects the yield for a U.S. Treasury Strip available on the date of grant with constant rate maturity approximating the option's expected life.  Expected life is calculated based on historical exercise behavior.  Volatility over the expected term of the options is evaluated with consideration given to prior periods that may need to be excluded based on events not likely to recur that had impacted PPL's volatility in those prior periods.  Management's expectations for future volatility, considering potential changes to PPL's business model and other economic conditions, are also reviewed in addition to the historical data to determine the final volatility assumption.  PPL had used historical volatility to value its stock options granted in 2010.  Beginning in 2011, PPL began using a mix of historic and implied volatility in response to the significant changes in its business model, moving from a primarily unregulated to a primarily regulated business model, as a result of the acquisitions of LKE and WPD Midlands.  The dividend yield is based on several factors, including PPL's most recent dividend payment, as of the grant date2015 was 34,967 and the forecasted stock price through 2013.  The assumptions used in the model were:   

   2012  2011  2010 
           
Risk-free interest rate  1.13%  2.34%  2.52%
Expected option life  6.17 years  5.71 years  5.43 years
Expected stock volatility  20.60%  21.60%  28.57%
Dividend yield  5.00%  5.93%  5.61%
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The weighted-averageweighted average grant date fair value of options granted was:

   2012  2011  2010 
           
PPL $ 2.48  $ 2.47  $ 4.70 
PPL Energy Supply   2.51    2.47    4.73 
PPL Electric   2.50    2.47    4.62 
LKE   2.51    2.47    

Stock option activity for 2012 was:

       Weighted-  
      Weighted Average   
     Average Remaining Aggregate
   Number Exercise Contractual Total Intrinsic
   of Options Price Per Share Term Value
PPL            
Outstanding at beginning of period   7,530,198  $ 30.65       
 Granted   1,948,550    28.19       
 Exercised   (263,094)   23.22       
 Forfeited   (81,109)   28.43       
Outstanding at end of period   9,134,545    30.36    6.3  $ 9 
Options exercisable at end of period   6,134,265    31.70    5.7    6 
              
PPL Energy Supply            
Outstanding at beginning of period   1,690,153  $ 30.79       
 Transferred   176,070    31.90       
 Granted   483,740    28.19       
 Exercised   (36,358)   24.35       
 Forfeited   (48,482)   29.34       
Outstanding at end of period   2,265,123    30.45    6.1  $ 2 
Options exercisable at end of period   1,529,711    31.80    4.9    1 
              
PPL Electric            
Outstanding at beginning of period   460,510  $ 31.05       
 Transferred   (176,070)   31.90       
 Granted   100,590    28.22       
 Exercised   (11,873)   25.67       
 Forfeited   (32,627)   27.07       
Outstanding at end of period   340,530    30.35    7.0    
Options exercisable at end of period   193,355    32.43    5.8    
              
LKE            
Outstanding at beginning of period   329,600  $ 25.77       
 Granted   354,490    28.17       
 Exercised   (49,243)   25.74       
Outstanding at end of period   634,847    27.11    8.6  $ 1 
Options exercisable at end of period   144,260    26.62    8.4    

PPL received $6 million in cash from stock options exercised in 2012.  The related tax savings were not significant for 2012.  Substantially all stock option awards are expected to vest.

The total intrinsic value of stock options exercised for the years ended December 31, 2012, 2011 and 2010 was not significant.$13.23 per share.

Compensation Expense

CompensationThe year ended December 31, 2015 includes an insignificant amount of compensation expense for Talen Energy Corporation restricted stock units, performance units and stock options accounted for as equity awards.

The year ended December 31, 2014 includes compensation expense of $33 million and the associated income tax benefit of $14 million for restricted stock, restricted stock units, performance units and stock options accounted for as equity awards was as follows:        from PPL, which included an allocation of PPL Services' expense.

   2012  2011  2010 
           
PPL $ 49  $ 36  $ 26 
PPL Energy Supply   23    16    20 
PPL Electric   11    8    6 
LKE   8    5    
315
The year ended December 31, 2013 includes compensation expense of $27 million and the associated income tax benefit related to above compensation expense was as follows:     

   2012  2011  2010 
           
PPL $ 20  $ 15  $ 11 
PPL Energy Supply   10    6    8 
PPL Electric   4    3    3 
LKE   4    2    

The income tax benefit PPL realized from stock-based awards vested or exercisedof $11 million for 2012 was not significant.

At December 31, 2012, unrecognized compensation expense related to nonvested restricted stock, restricted stock units, performance units and stock options accounted for as equity awards from PPL, which included an allocation of PPL Services' expense.
At December 31, 2015, unrecognized compensation expense and the weighted-average period for recognition related to nonvested restricted stock units, performance units and stock option awards was:   from Talen Energy was $11 million and 2.4 years.
Prior to the spinoff, restricted shares of PPL common stock and related restricted stock units, performance units and stock options were granted to officers and other key employees of Talen Energy. At December 31, 2014, these employees of Talen Energy had 1,457,900 of unvested shares of restricted stock and restricted stock units, 291,492 of performance units and 2,745,016 of outstanding stock options issued by PPL. The vesting of these awards was accelerated in 2015 in connection with the spinoff from PPL. See Note 1 for information on the recording of expense related to this acceleration and additional information on the spinoff from PPL. For the year ended December 31, 2015, compensation expense for these awards, excluding the acceleration, but including an allocation of PPL Services' compensation expense for similar awards, was $18 million.

Weighted-
UnrecognizedAverage
CompensationPeriod for
ExpenseRecognition
PPL$ 27 2.1 years
PPL Energy Supply 11 2.4 years
PPL Electric 2 2.2 years
LKE 2 1.8 years

13.  Retirement9.  Retirement and Postemployment Benefits

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Defined Benefits

Until JanuaryPrior to the June 1, 2012,2015 spinoff, the majority of PPL's subsidiaries domesticTalen Energy Supply's employees were eligible for pension benefits under a PPL non-contributory defined benefit pension plansplan, with benefits based on length of service and either career average pay or final average pay, as defined by the plans.  Effective Januaryplan. Prior to the June 1, 2012, PPL's domestic qualified pension plans were2015 spinoff, this plan was closed to all newly hired salaried employees. Newly hired bargaining unit employees will continue to be eligible under the plans based on their collective bargaining agreements.  Salaried employees hired on or after January 1, 2012 arewere eligible to participate in the newa PPL Retirement Savings Plan, a 401(k) savings plan with enhanced employer matching.contributions. Talen Energy was allocated costs of the PPL does not expectpension plan based on its employees' participation in the plan. Employees who participated in this PPL pension plan who became employees of Talen Energy Supply transferred into a significant near-term cost impactnewly created pension plan sponsored by Talen Energy Supply, which provides benefits similar to that of the PPL pension plan.

Prior to the June 1, 2015 spinoff, the majority of Talen Energy Supply's employees were also eligible for certain health care and life insurance benefits upon retirement through the PPL other postretirement benefit plans, which prior to June 1, 2015, were closed to all newly hired employees. Talen Energy Supply was allocated costs of the PPL plans based on its employees' participation in the plans. Employees who participated in the health care and life insurance plans and who became employees of Talen Energy Supply transferred into the newly created Talen Energy other postretirement benefit plans sponsored by Talen Energy Supply, which provide benefits similar to those of the PPL other postretirement benefit plans.

A remeasurement of the assets and the obligations for the PPL pension and other postretirement benefit plans was performed as of May 31, 2015 in order to separate the assets and obligations of the PPL plans attributable to Talen Energy, as required by the spinoff agreements. The Talen Energy pension plan assumed from PPL the pension benefit obligations for active plan participants who became employees of Talen Energy in connection with the spinoff and for individuals who terminated employment from Talen Energy Supply on or after July 1, 2000. A portion of the PPL pension plan assets were also allocated to the new Talen Energy pension plan. The asset allocation was based on the rules prescribed by ERISA (Employee Retirement Income Security Act) for allocating assets in connection with a pension plan spinoff. The Talen Energy other postretirement benefit plans assumed the other postretirement benefit obligations from PPL for active plan participants who became

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employees of Talen Energy in connection with the spinoff. PPL retained obligations attributable to existing retirees as of the date of the spinoff. A portion of the PPL other postretirement benefit plan assets, which were held in VEBA trusts and a 401(h) account, were also allocated to the new Talen Energy other postretirement benefit plans. The asset allocation was determined separately for each funding vehicle based on the ratio of the accumulated postretirement benefit obligation (APBO) assumed by Talen Energy to the total APBO attributed to each funding vehicle. As a result of the change.above, the net funded status of the new Talen Energy pension and other postretirement benefit plans at June 1, 2015 was a liability of $257 million.

Until January 1, 2012,The majority of Talen Montana's employees of PPL Montana wereare eligible for pension benefits under a cash balance pension plan. Effective January 1, 2012, that plan also was closed to all newly hired salaried employees. NewlyEffective September 1, 2014, that plan was closed to all newly hired bargaining unit employees will continue to be eligible under the plan based on their collective bargaining agreements.  Salaried employeesemployees. Newly hired on or after January 1, 2012employees are eligible to participate in a 401(k) savings plan with enhanced employer contributions. The majority of Talen Montana's employees are also eligible for certain health care and life insurance benefits upon retirement, under a retiree health plan sponsored by Talen Montana, which is now closed to newly hired employees. There were no changes to the new PPL Retirement Savings Plan.  PPLpension and other postretirement benefit plans for employees of Talen Montana does not expect a significant near-term cost impact as a result of the change.

The defined benefit pension plansspinoff transaction. However, PPL retained the liability for other postretirement benefits attributable to existing retirees of LKE and its subsidiaries were closed to new salaried and bargaining unit employees hired after December 31, 2005.  Employees hired after December 31, 2005 receive additional company contributions aboveTalen Montana as of the standard matching contributions to their savings plans.date of the spinoff.

Employees of certain of PPL Energy Supply'sTalen Energy's mechanical contracting companies are eligible for benefits under multiemployer plans sponsored by various unions.

Effective April 1, 2010, PPL WW's principalThe following table provides the components of net periodic defined benefit pension plan was closed to most new employees, exceptcosts for those meeting specific grandfathered participation rights.  WPD Midlands was acquired by PPL WEM on April 1, 2011.  WPD Midlands' defined benefit plan had been closed to new members, except for those meeting specific grandfathered participation rights, prior to acquisition.  New employees not eligible to participate in the plan are offered benefits under a defined contribution plan.

PPL and certain of its subsidiaries also provide supplemental retirement benefits to executivesTalen Energy pension and other key management employees through unfunded nonqualified retirement plans.
316
The majority of employees of PPL's domestic subsidiaries will become eligible for certain health care and life insurance benefits upon retirement through contributory plans.  Postretirement health benefits may be paid from 401(h) accounts established as part of the PPL Retirement Plan and the LG&E and KU Retirement Plan within the PPL Services Corporation Master Trust, funded VEBA trusts and company funds.  Postretirement benefits under the PPL Montana Retiree Health Plan are paid from company assets.  WPD does not sponsor any postretirement benefit plans other than pensions.

(PPL)

The following disclosures distinguish between the domestic (U.S.) and WPD (U.K.) pension plans.

    Pension Benefits         
    U.S. U.K. Other Postretirement Benefits
    2012  2011  2010  2012  2011  2010  2012  2011  2010 
PPL                           
Net periodic defined benefit costs                           
 (credits):                           
Service cost $ 103  $ 95  $ 64  $ 54  $ 44  $ 17  $ 12  $ 12  $ 8 
Interest cost   220    217    159    340    282    151    31    33    28 
Expected return on plan assets   (259)   (245)   (184)   (458)   (338)   (202)   (23)   (23)   (20)
Amortization of:                           
  Transition (asset) obligation                     2    2    5 
  Prior service cost   24    24    21    4    4    4    1       4 
  Actuarial (gain) loss   42    30    8    79    57    48    4    6    6 
Net periodic defined benefit costs                           
 (credits) prior to settlement                           
 charges and termination benefits   130    121    68    19    49    18    27    30    31 
Settlement charges   11                         
Termination benefits (a)            2    50             
Net periodic defined benefit costs                           
 (credits) $ 141  $ 121  $ 68  $ 21  $ 99  $ 18  $ 27  $ 30  $ 31 
                              
Other Changes in Plan Assets                           
 and Benefit Obligations                           
 Recognized in OCI and                           
 Regulatory Assets/Liabilities -                           
 Gross:                           
Settlements $ (11)                        
Net (gain) loss   372  $ 117  $ 142  $ 1,073  $ 152  $ 17  $ 13  $ (9) $ 20 
Prior service cost                           
 (credit)      8                (1)   10    (71)
Amortization of:                           
  Transition asset                     (2)   (2)   (5)
  Prior service cost   (24)   (24)   (21)   (4)   (4)   (4)   (1)      (4)
  Actuarial gain (loss)   (42)   (30)   (7)   (79)   (57)   (48)   (4)   (6)   (6)
Acquisition of regulatory assets/                           
 liabilities:                           
  Transition obligation                           4 
  Prior service cost         31                   6 
  Actuarial (gain) loss         303                   (2)
Total recognized in OCI and                           
 regulatory assets/liabilities (b)   295    71    448    990    91    (35)   5    (7)   (58)
                              
Total recognized in net periodic                           
 defined benefit costs, OCI and                           
 regulatory assets/liabilities (b) $ 436  $ 192  $ 516  $ 1,011  $ 190  $ (17) $ 32  $ 23  $ (27)

(a)Related to the WPD Midlands separations in the U.K.
(b)WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP.  As a result, WPD does not record regulatory assets/liabilities.

For PPL's U.S. pension benefits and for other postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities for the years ended December 31, were as follows:
for which the 2015 periods include seven months of costs under the newly formed Talen Energy plans and a full year of Talen Montana plans.

   U.S. Pension Benefits  Other Postretirement Benefits
    2012   2011   2010   2012   2011   2010 
                    
OCI $ 181  $ 47  $ 84  $ 12  $ (6) $ (40)
Regulatory assets/liabilities   114    24    364    (7)   (1)   (18)
Total recognized in OCI and                  
 regulatory assets/liabilities $ 295  $ 71  $ 448  $ 5  $ (7) $ (58)
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The estimated amounts to be amortized from AOCI and regulatory assets/liabilities into net periodic defined benefit costs in 2013 are as follows:

        Other
  Pension Benefits Postretirement
  U.S. U.K. Benefits
          
Prior service cost $ 22       
Actuarial loss   78  $ 154  $ 6 
Total $ 100  $ 154  $ 6 
          
Amortization from Balance Sheet:         
AOCI $ 43  $ 154  $ 3 
Regulatory assets/liabilities   57       3 
Total $ 100  $ 154  $ 6 

 Pension Benefits Other Postretirement Benefits
 2015
2014
2013 2015 2014 2013
Net periodic defined benefit costs (credits):           
Service cost$31
 $5
 $7
 $2
 $—
 $1
Interest cost46
 9
 8
 2
 1
 —
Expected return on plan assets(60) (11) (10) (3) —
 —
Amortization of:           
Actuarial (gain) loss16
 2
 3
 —
 —
 —
Curtailment charges (credits)—
 —
 —
 —
 (1) —
Net periodic defined benefit costs (credits)$33

$5

$8

$1

$—

$1
(PPL Energy Supply)                           
    Pension Benefits         
    U.S. U.K. (a) Other Postretirement Benefits
    2012  2011  2010  2012  2011  2010  2012  2011  2010 
PPL Energy Supply                           
Net periodic defined benefit costs                           
(credits):                           
Service cost $ 6  $ 5  $ 4        $ 17  $ 1  $ 1  $ 1 
Interest cost   7    7    7          151    1    1    1 
Expected return on plan assets   (9)   (9)   (7)         (202)         
Amortization of:                           
  Prior service cost                  4          
  Actuarial (gain) loss   2    2    2          48          
Net periodic defined benefit costs                           
 (credits) prior to settlement charges   6    5    6          18    2    2    2 
Net periodic defined benefit costs                           
 (credits) $ 6  $ 5  $ 6        $ 18  $ 2  $ 2  $ 2 
                              
Other Changes in Plan Assets                           
 and Benefit Obligations                           
 Recognized in OCI:                           
Current year net (gain) loss $ 16  $ 7  $ 4        $ 17     $ (2)   
Current year prior service credit                   $ (1)      
Amortization of:                           
  Prior service cost                  (4)         
  Actuarial gain (loss)   (2)   (2)   (2)         (48)         
Total recognized in OCI   14    5    2          (35)   (1)   (2)   
                              
Total recognized in net periodic                           
 defined benefit costs and OCI $ 20  $ 10  $ 8        $ (17) $ 1  $  $ 2 

(a)In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent.  See Note 9 for additional information.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
Other changes in plan assets and benefit obligations recognized in OCI:           
Curtailments$—
 $—
 $—
 $—
 $1
 $—
Net (gain) loss54
 26
 (15) —
 (1) (1)
Prior service cost (credit)3
 —
 —
 —
 —
 (3)
Amortization of:           
Actuarial gain (loss)(16) (2) (3) —
 —
 —
Prior service credit (cost)—
 —
 —
 1
 —
 —
Total recognized in OCI41
 24
 (18) 1
 —
 (4)
Total recognized in net periodic defined benefit costs and OCI$74
 $29
 $(10) $2
 $—
 $(3)

Actuarial loss of $3$20 million related to PPL Energy Supply's U.S. pension planthese plans is expected to be amortized from AOCI into net periodic defined benefit costs in 2013.     

(LKE)2016.

The following table provides the components of net periodic defined benefit costs for LKE's pension and other postretirement benefit plans for the years ended December 31, 2012, and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
318
    Pension Benefits Other Postretirement Benefits
    Successor  Predecessor Successor  Predecessor
    2012  2011  2010   2010  2012  2011  2010   2010 
LKE                          
Net periodic defined benefit costs                          
 (credits):                          
Service cost $ 22  $ 24  $ 4   $ 17  $ 4  $ 4  $ 1   $ 3 
Interest cost   64    67    11     54    9    10    1     9 
Expected return on plan assets   (70)   (64)   (9)    (45)   (4)   (3)       (2)
Amortization of:                          
  Transition obligation                2    2        1 
  Prior service cost   5    5    1     7    3    2        2 
  Actuarial (gain) loss   22    24    5     16    (1)          
Net periodic defined benefit costs $ 43  $ 56  $ 12   $ 49  $ 13  $ 15  $ 2   $ 13 
                             
Other Changes in Plan Assets                          
 and Benefit Obligations                          
 Recognized in OCI and                          
 Regulatory Assets/Liabilities -                          
 Gross:                          
Current year net (gain) loss $ 96  $ 29  $ (22)  $ 96  $ (11) $ (3) $ (2)  $ 3 
Current year prior service cost      8              11        
Amortization of:                          
  Transition obligation                (2)   (2)       (2)
  Prior service cost   (5)   (5)   (1)    (7)   (3)   (2)       (1)
  Actuarial gain (loss)   (22)   (24)   (5)    (16)   1           
Total recognized in OCI and                          
 regulatory assets/liabilities   69    8    (28)    73    (15)   4    (2)    
                             
Total recognized in net periodic                          
 defined benefit costs, OCI and regulatory                          
 assets/liabilities $ 112  $ 64  $ (16)  $ 122  $ (2) $ 19  $   $ 13 

For LKE's pension and other postretirement benefits, the amounts recognized in OCI and regulatory assets/liabilities are as follows at December 31, 2012, 2011 and 2010 for the Successor, and at October 31, 2010 for the Predecessor.
    Pension Benefits Other Postretirement Benefits
    Successor  Predecessor Successor  Predecessor
    2012  2011  2010   2010  2012  2011  2010   2010 
                             
                             
 OCI $ 34  $ 1  $ (8)  $ 32  $ (1) $ 2  $ (1)  $ (1)
 Regulatory assets/liabilities   35    7    (20)    41    (14)   2    (1)    1 
 Total recognized in OCI and                          
  regulatory assets/liabilities $ 69  $ 8  $ (28)  $ 73  $ (15) $ 4  $ (2)  $ 

The estimated amounts to be amortized from AOCI and regulatory assets/liabilities into net periodic defined benefit costs for LKE in 2013 are as follows.

     Other
  Pension Postretirement
  Benefits Benefits
       
Prior service cost $ 5  $ 3 
Actuarial loss   31    (1)
Total $ 36  $ 2 
       
Amortization from Balance Sheet:      
Regulatory assets/liabilities $ 36  $ 2 
Total $ 36  $ 2 

(LG&E)

The following table provides the components of net periodic defined benefit costs for LG&E's pension benefit plan for the years ended December 31, 2012 and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
319
    Pension Benefits
    Successor   Predecessor
    2012  2011  2010    2010 
LG&E              
Net periodic defined benefit costs (credits):              
Service cost $ 2  $ 2       $ 1 
Interest cost   14    14  $ 2      12 
Expected return on plan assets   (19)   (18)   (3)     (13)
Amortization of:              
  Prior service cost   3    2    1      2 
  Actuarial loss   11    11    2      6 
Net periodic defined benefit costs $ 11  $ 11  $ 2    $ 8 
                 
Other Changes in Plan Assets and Benefit Obligations              
 Recognized in Regulatory Assets - Gross:              
Current year net (gain) loss $ 18  $ 15  $ (5)   $ 18 
Current year prior service cost      9         
Amortization of:              
  Prior service cost   (2)   (2)        (2)
  Actuarial (loss)   (11)   (11)   (2)     (6)
Total recognized in regulatory assets   5    11    (7)     10 
                 
Total recognized in net periodic defined benefit costs and regulatory assets $ 16  $ 22  $ (5)   $ 18 

The estimated amounts to be amortized from regulatory assets into net periodic defined benefit costs for LG&E in 2013 are as follows.

Pension
Benefits
Prior service cost$ 2 
Actuarial loss 13 
Total$ 15 

(PPL, PPL Energy Supply and PPL Electric)

Net periodic defined benefit costs (credits) were charged to operating expense, excluding amounts charged to construction and other non-expense accounts were:accounts.

104

  Pension Benefits         
  U.S. U.K. Other Postretirement Benefits
  2012  2011  2010  2012  2011  2010(a) 2012  2011  2010 
                            
PPL $ 119  $ 98  $ 59  $ 25  $ 82  $ 16  $ 22  $ 24  $ 27 
PPL Energy Supply   37    27    24          16    6    7    12 
PPL Electric (b)   19    14    12             3    4    8 
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(a)As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, these amounts are included in "Income (Loss) from Discontinued Operations (net of income taxes)" on PPL Energy Supply's Statements of Income.  See Note 9 for additional information.
(b)PPL Electric does not directly sponsor any defined benefit plans.  PPL Electric was allocated these costs of defined benefit plans sponsored by PPL Services, based on its participation in those plans, which management believes are reasonable.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
 $48
 $39
 $45
 $2
 $3
 $6

In the table above, for PPL Energy Supply, amounts include costs for the specific plans it sponsorssponsored by Talen Energy and its subsidiaries and the following allocated costs of definedthe PPL pension and other postretirement benefit plans sponsored by PPL Services,prior to the spinoff, based on PPLTalen Energy Supply's participation in those plans, which management believes are reasonable:were reasonable at the time:
    Pension Benefits  Other Postretirement Benefits
     2012   2011   2010   2012   2011   2010 
                     
  PPL Energy Supply $ 31  $ 23  $ 19  $ 5  $6  $ 10 
 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
 $16
 $34
 $38
 $—
 $3
 $5

(LKE, LG&EAt December 31, 2014 or June 1, 2015, as applicable, the plan sponsors adopted the mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables) for all applicable defined benefit pension and KU)other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors also selected the IRS BB 2-Dimensional mortality improvement scale on a generational basis for all applicable defined benefit pension and other postretirement benefit plans. These mortality assumptions reflect the recognition of both improved life expectancies and the expectation of continuing improvements in life expectancies.

The following table provides net periodic defined benefit costs charged to operating expense for the years ended December 31, 2012, and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.
320
  Pension Benefits Other Postretirement Benefits
  Successor  Predecessor  Successor  Predecessor
  2012  2011  2010   2010   2012  2011  2010   2010 
                            
LKE $ 31  $ 40  $ 9   $ 37   $ 9  $ 11  $ 2   $ 9 
LG&E   13    16    3     12     5    5    1     4 
KU (a)   8    10    2     8     3    4    1     3 

(a)KU does not directly sponsor any defined benefit plans.  KU was allocated these costs of defined benefit plans sponsored by LKE, based on its participation in those plans, which management believes are reasonable.             

In the table above, for LG&E, amounts include costs for the specific plans it sponsors and the following allocated costs of defined benefit plans sponsored by LKE, based on its participation in those plans, which management believes are reasonable.
  Pension Benefits  Other Postretirement Benefits
  Successor  Predecessor  Successor  Predecessor
  2012  2011  2010   2010   2012  2011  2010   2010 
                            
LG&E $ 5  $ 7  $ 1   $ 6   $ 2  $ 5  $ 1   $ 4 

(PPL and PPL Energy Supply)

The following weighted-average assumptions were used in the valuation of the benefit obligations at December 31.
 Pension Benefits Other Postretirement Benefits
 2015 2014 2015 2014
Discount rate4.65% 4.28% 4.60% 3.81%
Rate of compensation increase3.98% 4.03% 3.98% 4.03%

   Pension Benefits      
   U.S. U.K. Other Postretirement Benefits
   2012  2011  2012  2011  2012  2011 
PPL                  
 Discount rate  4.22%  5.06%  4.27%  5.24%  4.00%  4.80%
 Rate of compensation increase  3.98%  4.02%  4.00%  4.00%  3.97%  4.00%
                   
PPL Energy Supply                  
 Discount rate  4.25%  5.12%        3.77%  4.60%
 Rate of compensation increase  3.95%  4.00%        3.95%  4.00%

(LKE and LG&E)

The following table provides the weighted-average assumptions used in the valuation of the benefit obligations at December 31.

               
    Pension Benefits Other Postretirement Benefits
    2012  2011  2012  2011 
LKE             
 Discount rate   4.24%  5.08%  3.99%  4.78%
 Rate of compensation increase   4.00%  4.00%  4.00%  4.00%
LG&E             
 Discount rate   4.20%  5.00%      
 Rate of compensation increase   N/A  N/A      

(PPL and PPL Energy Supply)

The following weighted-average assumptions were used to determine the net periodic defined benefit costs for the year ended December 31.

   Pension Benefits         
   U.S. U.K. Other Postretirement Benefits
   2012  2011  2010  2012  2011  2010  2012  2011  2010 
PPL                           
 Discount rate  5.06%  5.42%  5.96%  5.24%  5.59%  5.59%  4.80%  5.14%  5.47%
 Rate of compensation increase  4.02%  4.88%  4.79%  4.00%  3.75%  4.00%  4.00%  4.90%  4.78%
 Expected return on plan assets (a)  7.07%  7.25%  7.96%  7.17%  7.04%  7.91%  5.99%  6.57%  6.90%
                            
PPL Energy Supply                           
 Discount rate  5.12%  5.47%  6.00%        5.59%  4.60%  4.95%  5.55%
 Rate of compensation increase  4.00%  4.75%  4.75%        4.00%  4.00%  4.75%  4.75%
 Expected return on plan assets (a)  7.00%  7.25%  8.00%        7.91%  N/A  N/A  N/A
321
(LKE and LG&E)

The following table provides the weighted-average assumptions used to determine the net periodic defined benefit costsTalen Energy's plans for the years ended December 31, 2012, and 2011, and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.31.

 Pension Benefits Other Postretirement Benefits
 2015 2014 2013 2015 2014 2013
Discount rate4.41% 5.18% 4.25% 4.27% 4.51% 3.77%
Rate of compensation increase3.99% 3.94% 3.95% 3.99% 3.94% 3.95%
Expected return on plan assets (a)7.00% 7.00% 7.00% 6.37% N/A
 N/A
   Pension Benefits Other Postretirement Benefits
   Successor  Predecessor Successor  Predecessor
   2012  2011  2010   2010  2012  2011  2010   2010 
LKE                          
 Discount rate  5.09%  5.49%  5.40%   6.11%  4.78%  5.12%  4.94%   5.82%
 Rate of compensation increase  4.00%  5.25%  5.25%   5.25%  4.00%  5.25%  5.25%   5.25%
 Expected return on plan assets (a)  7.25%  7.25%  7.25%   7.75%  7.02%  7.16%  7.04%   7.20%
LG&E                          
 Discount rate  5.00%  5.39%  5.28%   6.08%             
 Rate of compensation increase  N/A  N/A  N/A   N/A             
 Expected return on plan assets (a)  7.25%  7.25%  7.25%   7.75%             

(PPL, PPL Energy Supply, LKE and LG&E)

(a)The expected long-term rates of return for PPL's, PPL Energy Supply's, LKE's and LG&E's U.S. pension and other postretirement benefits have been developedare based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.  PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk.  Each plan's specific current and expected asset allocation isallocations are also considered in developing a reasonable return assumption.

The expected long-term rates of return for PPL's U.K. pension plans have been developed by PPL management with assistance from an independent actuary using a best estimate of expected returns, volatilities and correlations for each asset class.  The best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.

(PPL and PPL Energy Supply)

The following table provides the assumed health care cost trend rates for the year ended December 31:

     2012  2011  2010 
PPL and PPL Energy Supply         
 Health care cost trend rate assumed for next year         
   - obligations  8.0%  8.5%  9.0%
   - cost  8.5%  9.0%  8.0%
 Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)         
   - obligations  5.5%  5.5%  5.5%
   - cost  5.5%  5.5%  5.5%
 Year that the rate reaches the ultimate trend rate         
   - obligations  2019   2019   2019 
   - cost  2019   2019   2016 

(LKE)

The following table provides the assumed health care cost trend rates for the years ended December 31, 2012, 2011 and November 1, 2010 through December 31, 2010, for the Successor and January 1, 2010 through October 31, 2010, for the Predecessor.

     Successor  Predecessor
     2012  2011  2010   2010 
LKE             
 Health care cost trend rate assumed for next year             
   - obligations  8.0%  8.5%  9.0%   7.8%
   - cost  8.5%  9.0%  9.0%   8.0%
 Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)             
   - obligations  5.5%  5.5%  5.5%   4.5%
   - cost  5.5%  5.5%  5.5%   4.5%
 Year that the rate reaches the ultimate trend rate             
   - obligations  2019   2019   2019    2029 
   - cost  2019   2019   2019    2029 
31.
322
(PPL and LKE)
 2015 2014 2013
Health care cost trend rate assumed for next year     
obligations6.80% 7.20% 7.60%
costs7.20% 7.60% 8.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend)     
obligations5.00% 5.00% 5.00%
costs5.00% 5.00% 5.50%
Year that the rate reaches the ultimate trend rate     
obligations2020
 2020
 2020
costs2020
 2020
 2019

A one percentage point change in the assumed health care costs trend rate assumption would have had the following effects onbeen insignificant to the other postretirement benefit plans in 2012:2015.

105

   One Percentage Point
   Increase Decrease
Effect on accumulated postretirement benefit obligation      
 PPL $ 7  $ (6)
 LKE   5    (4)
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(PPL Energy Supply)

The effects on PPL Energy Supply's other postretirement benefit plan would not have been significant.

(PPL)

The funded status of the PPLTalen Energy's plans at December 31 was as follows:

    Pension Benefits      
    U.S. U.K. Other Postretirement Benefits
    2012  2011  2012  2011  2012  2011 
Change in Benefit Obligation                  
Benefit Obligation, beginning of period $ 4,381  $ 4,007  $ 6,638  $ 2,841  $ 687  $ 667 
  Service cost   103    95    54    44    12    12 
  Interest cost   220    217    340    282    31    33 
  Participant contributions         15    11    6    5 
  Plan amendments      8          (1)   10 
  Actuarial loss   546    220    1,081    257    31    6 
  Acquisition (a)            3,501       
  Settlements   (25)               
  Termination benefits         2    50       
  Net transfer in (out)         12          
  Actual expenses paid   (3)               
  Gross benefits paid   (176)   (166)   (397)   (309)   (46)   (47)
  Federal subsidy               2    1 
  Currency conversion         143    (39)      
Benefit Obligation, end of period   5,046    4,381    7,888    6,638    722    687 
                     
Change in Plan Assets                  
Plan assets at fair value, beginning of period   3,471    2,819    6,351    2,524    391    360 
  Actual return on plan assets   432    349    476    444    42    38 
  Employer contributions   239    470    341    164    27    33 
  Participant contributions         15    11    5    5 
  Acquisition (a)            3,567       
  Settlements   (25)               
  Actual expenses paid   (2)   (1)            
  Gross benefits paid   (176)   (166)   (397)   (309)   (44)   (45)
  Currency conversion         125    (50)      
Plan assets at fair value, end of period   3,939    3,471    6,911    6,351    421    391 
                     
Funded Status, end of period $ (1,107) $ (910) $ (977) $ (287) $ (301) $ (296)
                     
Amounts recognized in the Balance                  
 Sheets consist of:                  
  Noncurrent asset          $ 130       
  Current liability $ (8) $ (29)       $ (1) $ (1)
  Noncurrent liability   (1,099)   (881) $ (977)   (417)   (300)   (295)
Net amount recognized, end of period $ (1,107) $ (910) $ (977) $ (287) $ (301) $ (296)
                     
Amounts recognized in AOCI and                  
 regulatory assets/liabilities (pre-tax)                  
 consist of:                  
Transition obligation                $ 2 
Prior service cost (credit) $ 91  $ 115  $ 1  $ 3  $ (7)   (5)
Net actuarial loss   1,241    922    2,184    1,191    106    97 
Total (b) $ 1,332  $ 1,037  $ 2,185  $ 1,194  $ 99  $ 94 
                     
Total accumulated benefit obligation                  
 for defined benefit pension plans $ 4,569  $ 3,949  $ 7,259  $ 6,144       
323
 Pension Benefits Other Postretirement Benefits
 2015 2014 2015 2014
Change in Benefit Obligation       
Benefit obligation, beginning of period$210
 $163
 $10
 $12
Transfer of benefit obligation at spinoff (a)1,416
 —
 80
 —
Service cost31
 5
 2
 —
Interest cost46
 9
 2
 1
Plan amendments3
 —
 —
 —
Actuarial (gain) loss(41) 38
 (4) (1)
Net Transfers in (out)—
 —
 (3) —
Curtailments—
 —
 —
 (1)
Gross benefits paid(51) (5) —
 (1)
Benefit obligation, end of period$1,614
 $210
 $87
 $10
        
Change in Plan Assets       
Plan assets at fair value, beginning of period$170
 $147
 $—
 $—
Transfer of plan assets at fair value at spinoff (a)1,159
 —
 80
 —
Actual return on plan assets(35) 22
 (2) —
Employer contributions32
 6
 1
 1
Gross benefits paid(52) (5) (1) (1)
Plan assets at fair value, end of period1,274
 170
 78
 —
Funded status end of period$(340) $(40) $(9) $(10)
        
Amounts recognized in the Balance Sheets consist of:       
Current Liability$—
 $—
 $—
 $(1)
Noncurrent liability(340) (40) (9) (9)
Net amount recognized, end of period$(340) $(40) $(9) $(10)
        
Amounts recognized in AOCI (pre-tax) consist of:       
Prior service cost (credit)$2
 $—
 $(5) $(4)
Net actuarial (gain) loss451
 59
 8
 —
Total$453
 $59
 $3
 $(4)
        
Total accumulated benefit obligation for defined benefit pension plans$1,500
 $210
 
 

(a)IncludesValues determined as of the pension plans of WPD Midlands, which was acquired in 2011.  See Note 10 for additional information.spinoff date as discussed above.
(b)WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP.  As a result, WPD does not record regulatory assets/liabilities.

For PPL's U.S. pension and other postretirement benefit plans, the amounts recognized in AOCI and regulatory assets/liabilities at December 31 were as follows:

  U.S. Pension Benefits Other Postretirement Benefits
  2012  2011  2012  2011 
         
AOCI $ 659  $ 481  $ 59  $ 56 
Regulatory assets/liabilities   673    556    40    38 
Total $ 1,332  $ 1,037  $ 99  $ 94 

All of PPL's U.S.Talen Energy's pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011.  All of PPL's other postretirement benefit plans had accumulated postretirement benefit obligations in excessthe fair value of plan assets at December 31, 20122015 and 2011.

For the U.K. pension plans of PPL WEM, projected benefit obligations of $4.3 billion were in excess of plan assets of $4.1 billion at December 31, 2012.

For the U.K. pension plans of PPL WW, projected and accumulated benefit obligations were in excess of plan assets at December 31 as follows (in billions):

  2012  2011 
       
Projected benefit obligation $ 3.6  $ 3.0 
Accumulated benefit obligation   3.3    2.8 
Fair value of plan assets   2.8    2.6 

(PPL Energy Supply)               
                     
The funded status of the PPL Energy Supply plans were as follows:
                     
    Pension Benefits      
    U.S. U.K. Other Postretirement Benefits
    2012  2011  2012  2011  2012  2011 
Change in Benefit Obligation                  
Benefit Obligation, beginning of period $ 143  $ 121     $ 2,841  $ 17  $ 18 
  Service cost   6    5          1    1 
  Interest cost   7    7          1    1 
  Plan amendments               (1)   
  Actuarial loss   23    13             (2)
  Distribution to parent (a)            (2,841)      
  Actual expenses paid                  (1)
  Gross benefits paid   (3)   (3)         (1)   
Benefit Obligation, end of period   176    143          17    17 
                     
Change in Plan Assets                  
Plan assets at fair value, beginning of                  
 period   132    106       2,524       
  Actual return on plan assets   16    14             
  Employer contributions   4    15             
  Distribution to parent (a)            (2,524)      
  Gross benefits paid   (3)   (3)            
Plan assets at fair value, end of period   149    132             
                     
Funded Status, end of period $ (27) $ (11)    $  $ (17) $ (17)
                     
Amounts recognized in the Balance                  
 Sheets consist of:                  
  Current liability             $ (1) $ (1)
  Noncurrent liability $ (27) $ (11)         (16)   (16)
Net amount recognized, end of period $ (27) $ (11)       $ (17) $ (17)
324
    Pension Benefits      
    U.S. U.K. Other Postretirement Benefits
    2012  2011  2012  2011  2012  2011 
Amounts recognized in AOCI                  
 (pre-tax) consist of:                  
Prior service cost (credit)    $ 1        $ (1)   
Net actuarial loss $ 52    38          2  $ 2 
Total $ 52  $ 39        $ 1  $ 2 
                     
Total accumulated benefit obligation                  
 for defined benefit pension plans $ 176  $ 143             

(a)As a result of PPL Energy Supply's January 2011 distribution of its membership interest in PPL Global to its parent, PPL Energy Funding, the funded status and AOCI were removed from the balance sheet in January 2011.  See Note 9 for additional information.

PPL Energy Supply's pension plan had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011.  PPL Energy Supply's other postretirement benefit plan had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2012 and 2011.2014.

In addition to the plans it sponsors, PPLTalen Energy Supply and its subsidiaries arewere allocated a portion of the funded status and costs of the defined benefit plans sponsored by PPL Services based on their participation in those plans prior to the spinoff, which management believes are reasonable.were reasonable at that time. The actuarially determined obligations of current active employees arewere used as a basis to allocate total plan activity, including active and retiree costs and obligations. Allocations to PPLTalen Energy Supply resulted in liabilities at December 31, 2014 as follows:

  2012  2011 
       
Funded status of the pension plans $ 268  $ 204 
Other postretirement benefits   60    51 
Pension plans$259
Other postretirement benefit plans34

(LKE)

The funded status of the LKE plans was as follows.

    Pension Benefits Other Postretirement Benefits
    2012  2011  2012  2011 
Change in Benefit Obligation            
Benefit Obligation, beginning of period $ 1,306  $ 1,229  $ 214  $ 204 
  Service cost   22    24    4    4 
  Interest cost   63    67    9    10 
  Plan amendments      9       10 
  Actuarial loss (gain)   144    25    (8)   (3)
  Gross benefits paid   (48)   (48)   (11)   (12)
  Federal subsidy         1    1 
Benefit Obligation, end of period   1,487    1,306    209    214 
               
Change in Plan Assets            
Plan assets at fair value, beginning of period   944    778    58    49 
  Actual return on plan assets   117    62    8    3 
  Employer contributions   57    152    13    18 
  Gross benefits paid   (48)   (48)   (11)   (12)
Plan assets at fair value, end of period   1,070    944    68    58 
               
Funded Status, end of period $ (417) $ (362) $ (141) $ (156)
               
Amounts recognized in the Balance            
 Sheets consist of:            
  Current liability $ (3) $ (3)      
  Noncurrent liability   (414)   (359) $ (141) $ (156)
Net amount recognized, end of period $ (417) $ (362) $ (141) $ (156)
               
Amounts recognized in AOCI and            
 regulatory assets/liabilities (pre-tax)            
 consist of:            
Transition obligation          $ 2 
Prior service cost $ 28  $ 34  $ 11    14 
Net actuarial (gain) loss   355    280    (17)   (7)
Total $ 383  $ 314  $ (6) $ 9 
               
Total accumulated benefit obligation            
 for defined benefit pension plans $ 1,319  $ 1,141       
325
At December 31, the amounts recognized in AOCI and regulatory assets/liabilities are as follows.
   Pension Benefits Other Postretirement Benefits
   2012  2011  2012  2011 
          
 AOCI $ 27  $ (7)    $ 1 
 Regulatory assets/liabilities   356    321  $ (6)   8 
 Total $ 383  $ 314  $ (6) $ 9 

All of LKE's pension plans had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011.  LKE's other postretirement benefit plan had accumulated postretirement benefit obligations in excess of plan assets at December 31, 2012 and 2011.

(LG&E)

The funded status of the LG&E plan was as follows.    

        Pension Benefits
        2012  2011 
Change in Benefit Obligation          
Benefit Obligation, beginning of period     $ 298  $ 274 
  Service cost       1    2 
  Interest cost       14    14 
  Plan amendments          9 
  Actuarial loss       32    14 
  Gross benefits paid       (14)   (15)
Benefit Obligation, end of period       331    298 
             
Change in Plan Assets          
Plan assets at fair value, beginning of period       256    217 
  Actual return on plan assets       32    16 
  Employer contributions       13    38 
  Gross benefits paid       (14)   (15)
Plan assets at fair value, end of period       287    256 
             
Funded Status, end of period     $ (44) $ (42)
             
Amounts recognized in the Balance Sheets consist of:          
  Noncurrent liability     $ (44) $ (42)
Net amount recognized, end of period     $ (44) $ (42)
             
Amounts recognized in regulatory assets (pre-tax)          
 consist of:          
Prior service cost     $ 17  $ 20 
Net actuarial loss       123    115 
Total     $ 140  $ 135 
             
Total accumulated benefit obligation for defined benefit pension plan     $ 328  $ 292 

LG&E's pension plan had projected and accumulated benefit obligations in excess of plan assets at December 31, 2012 and 2011.

In addition to the plan it sponsors, LG&E is allocated a portion of the funded status and costs of certain defined benefit plans sponsored by LKE based on its participation in those plans, which management believes are reasonable.  The actuarially determined obligations of current active employees and retired employees are used as a basis to allocate total plan activity, including active and retiree costs and obligations.  Allocations to LG&E resulted in liabilities at December 31 as follows.    

  2012  2011 
       
Funded status of the pension plans $ 58  $ 53 
Other postretirement benefits   81    87 

(PPL and PPL Energy Supply)

PPL Energy Supply'sTalen Energy's mechanical contracting subsidiaries make contributions to over 7060 multiemployer pension plans, based on the bargaining units from which labor is procured. The risks of participating in these multiemployer plans are different from single-employer plans in the following aspects:


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·
Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.

·If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

·If PPL Energy Supply'sIf Talen Energy's mechanical contracting subsidiaries choose to stop participating in some of their multiemployer plans, they may be required to pay those plans an amount based on the unfunded status of the plan, referred to as a withdrawal liability.

PPLTalen Energy Supply identified the Steamfitters Local Union No. 420 Pension Plan, EIN/Plan Number 23-2004424/001 as the only significant plan to which the most significant contributions are made. Contributions to this plan by PPL Energy Supply'sTalen Energy's mechanical contracting companies were $5 million for 2012, $5 million for 20112015, 2014 and $4 million for 2010.2013. At the date the financial statements were issued, the Form 5500 was not available for the plan year ending in 2012.2015. Therefore, the following disclosures specific to this plan are being made based on the Form 5500s filed for the plan years ended December 31, 20112014 and 2010.  PPL Energy Supply's2013. Talen Energy's mechanical contracting subsidiaries were notsubsidiary H.T. Lyons was identified individually as a greater than 5% contributorscontributor on the Form 5500s.  However, the combined contributions of the three subsidiaries contributing to the plan had exceeded 5%. The plan had a Pension Protection Act zone status of yellow and red, without utilizing an extended amortization period, as of December 31, 20112014 and 2010.2013. In addition, the plan is subject to a rehabilitation plan and surcharges have been applied to participating employer contributions. The expiration date of the collective-bargaining agreement related to those employees participating in this plan is April 30, 2014.September 18, 2016. There were no other plans deemed individually significant based on a multifaceted assessment of each plan.  This assessment included review of the funded/zone status of each plan and PPL Energy Supply's potential obligations under the plan and the number of participating employers contributing to the plan.assessment.

PPL Energy Supply'sTalen Energy's mechanical contracting subsidiaries also participate in multiemployer other postretirement plans that provide for retiree life insurance and health benefits.

The table below details total contributions to all multiemployer pension and other postretirement plans, including the plan identified as significant above. The contribution amounts fluctuate each year based on the volume of work and type of projects undertaken from year to year.

  2012  2011  2010 
          
Pension Plans $31  $36  $26 
Other Postretirement Medical Plans  28   31   23 
Total Contributions $59  $67  $49 
 2015 2014 2013
Pension plans$34
 $40
 $36
Other postretirement benefit plans26
 33
 32
Total contributions$60
 $73
 $68

PPL Energy Supply maintains a liability for the cost of health care of retired miners of former subsidiaries that had been engaged in coal mining, as required by the Coal Industry Retiree Health Benefit Act of 1992.  Plan Assets

At December 31, 2012, the liability was $3 million.  The liability is the net of $67 million of estimated future benefit payments offset by $35 million of assets in a retired miners VEBA trust and an additional $29 million of excess assets available in a Black Lung Trust that can be used to fund the health care benefits of retired miners.

(PPL Electric)

Although PPL Electric does not directly sponsor any defined benefit2015, Talen Energy's pension plans it is allocated a portion of the funded status and costs of plans sponsored by PPL Services based on its participation in those plans, which management believes are reasonable.  The actuarially determined obligations of current active employees are used as a basis to allocate total plan activity, including active and retiree costs and obligations.  Allocations to PPL Electric resulted in liabilities at December 31 as follows:

  2012  2011 
       
Funded status of the pension plans $ 237  $ 186 
Other postretirement benefits   61    53 
327
(KU)

Although KU does not directly sponsor any defined benefit plans, it is allocated a portion of the funded status and costs of plans sponsored by LKE based on its participation in those plans, which management believes are reasonable.  The actuarially determined obligations of current active employees and retired employees of KU are used as a basis to allocate total plan activity, including active and retiree costs and obligations.  Allocations to KU resulted in liabilities at December 31 as follows.

  2012  2011 
       
Funded status of the pension plans $ 104  $ 83 
Other postretirement benefits   53    62 

Plan Assets - U.S. Pension Plans

(PPL, PPL Energy Supply, LKE and LG&E)

PPL's primary legacy pension plan and the pension plan in which employees of PPL Montana participate are invested in the PPL Services CorporationTalen Energy Retirement Plans Master Trust (the Master Trust) that also includes a 401(h) account that is restricted for certain other postretirement benefit obligations.  Through December 31, 2011,obligations of Talen Energy. Prior to the plans sponsored by LKE, including LG&E'sspinoff from PPL, the pension plan assets were invested by PPL in Pension Trusts that also included a 401(h) account that is restricted for certain other postretirement benefit obligations.  Effective January 1, 2012, the assets in the LKE Pension Trusts were transferred into the PPL Services Corporation Master Trust.  master trust maintained by PPL.

The investment strategy for the master trustMaster Trust is to achieve a risk-adjusted return on a mix of assets that, in combination with PPL'sTalen Energy's funding policy, will ensure that sufficient assets are available to provide long-term growth and liquidity for benefit payments.payments, while also managing the duration of the assets to complement the duration of the liabilities. The master trustMaster Trust benefits from a wide diversification of asset types, investment fund strategies and external investment fund managers, and therefore has no significant concentration of risk.

The investment policy of the PPL Services Corporation Master Trust outlines investment objectives and defines the responsibilities of the EBPB,Retirement Plan Committee of Talen Energy Corporation, which is the named fiduciary, external investment managers, investment advisor and trustee and custodian. The investment policy is reviewed annually by PPL'sTalen Energy Corporation's Board of Directors.

The EBPBRetirement Plan Committee created a risk management framework around the trust assets and pension liabilities. This framework considers the trust assets as being composed of three sub-portfolios:  the growth, immunizing and liquidity portfolios. The growth portfolio is comprised of investments that generate a return at a reasonable risk, including equity securities, certain debt securities and alternative investments. The immunizing portfolio consists of debt securities, generally with long durations, and derivative positions that will typically have long durations.positions. The immunizing portfolio is designed to offset a portion of the change in the pension liabilities due to changes in interest rates. The liquidity portfolio consists primarily of cash and cash equivalents.

Target asset allocation ranges have been developed for each portfolio on a plan basisthe Master Trust based on input from external consultants with a goal of limiting funded status volatility. The EBPBRetirement Plan Committee monitors the investments in each portfolio on a plan basis,the Master Trust, and seeks to

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obtain a target portfolio that emphasizes reduction of risk of loss from market volatility. In pursuing that goal, the EBPBRetirement Plan Committee establishes revised guidelines from time to time.  EBPB investment guidelines on a plan basis, as well as the weighted average of such guidelines, as of the end of 2012 are presented below.

The asset allocation for the truststrust and the target allocation prescribed by the investment guidelines by portfolio at December 31 are as follows:

PPL Services Corporation Master Trust

                 
         2012 Target Asset Allocation (a)
   Percentage of trust assets  Weighted      
   2012 (a)  2011    Average  PPL Plans  LKE Plans
                
Growth Portfolio   58%   57%  56%  55%  59%
 Equity securities   31%   31%         
 Debt securities (b)   18%   17%         
 Alternative investments   9%   9%         
Immunizing Portfolio   41%   41%  42%  43%  38%
 Debt securities (b)   40%   40%         
 Derivatives   1%   1%         
Liquidity Portfolio   1%   2%  2%  2%  3%
Total   100%   100%  100%  100%  100%

328
 Percentage of trust assets Target Asset Allocation
 2015 2015
Growth Portfolio52% 55%
Equity securities24%  
Debt securities (a)14%  
Alternative investments14%  
Immunizing Portfolio46%
44%
Debt securities (a)40%  
Derivatives6%  
Liquidity Portfolio2% 1%
Total100%
100%
(a)Allocations exclude consideration of cash for the WKE Bargaining Employees' Retirement Plan and a guaranteed annuity contract held by the LG&E and KU Retirement Plan.
(b)(a)Includes commingled debt funds, which PPLTalen Energy treats as debt securities for asset allocation purposes.
LG&E and KU Energy LLC Pension Trusts      
   Percentage Target Asset
    of trust assets Allocation
  2011  2011 
        
Growth Portfolio   54%   59%
 Equity securities   33%   
 Debt securities (a)   21%   
Immunizing Portfolio   34%   38%
 Debt securities (a) (b)   34%   
Liquidity Portfolio (b)   12%   3%
Total   100%   100%

(a)Includes commingled debt funds, which LKE treats as debt securities for asset allocation purposes.
(b)The asset allocation for this portfolio was not within the established target range due to the transition of assets at the end of 2011 in anticipation of transfer into the PPL Services Corporation Master Trust in January 2012.                   

(PPL Energy Supply)

PPLPrior to the spinoff, the assets of the Talen Montana a subsidiary of PPL Energy Supply, has a pension plan whose assets arewere invested solely in the PPL Services Corporation Master Trust, which is fully disclosed below.a master trust maintained by PPL. The fair value of this plan's assets of $149$170 million at December 31, 2012 represents2014 represented an interest of approximately 4% in thePPL's master trust.

(LKE)

LKE has pension plans, including LG&E's plan, whose assets, effective January 1, 2012, are invested solely in the PPL Services Corporation Master Trust, which is fully disclosed below.  The fair value of these plans' assets of $1.1 billion at December 31, 2012 represents an interest of approximately 26% in the master trust.

(LG&E)

LG&E has a pension plan whose assets, effective January 1, 2012, are invested solely in the PPL Services Corporation Master Trust, which is fully disclosed below.  The fair value of this plan's assets of $287 million at December 31, 2012 represents an interest of approximately 7% in the master trust.  At December 31, 2011, this plan's assets were invested solely in the LG&E and KU Energy LLC Pension Trusts, which is also fully disclosed below.  The fair value of this plan's assets of $256 million at December 31, 2011 represents an interest of approximately 26% in the pension trust.

(PPL, PPL Energy Supply, LKE and LG&E)

The fair value of net assets in the U.S. pension plan trustsMaster Trust by asset class and level within the fair value hierarchy was:

     December 31, 2012 December 31, 2011
        Fair Value Measurements Using    Fair Value Measurements Using
     Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
PPL Services Corporation Master Trust                        
Cash and cash equivalents $ 84  $ 84        $ 78  $ 78       
Equity securities:                        
  U.S.:                        
   Large-cap   558    206  $ 352       371    247  $ 124    
   Small-cap   124    124          112    112       
   Commingled debt   676    56    620       458       458    
  International   557    184    373       299    102    197    
Debt securities:                        
  U.S. Treasury and U.S. government sponsored                        
   agency   704    634    70       515    443    72    
  Residential/commercial backed securities   12       11  $ 1    9       9    
  Corporate   874       847    27    446       439  $ 7 
  Other   24       23    1    10       10    
  International   7       7       6       6    
 December 31, 2015
 Fair Value Measurement Using
 Total Level 1 Level 2 Level 3
Talen Energy Retirement Plans Master Trust       
Cash and cash equivalents$108
 $108
 $—
 $—
Equity securities:
      
U.S.:
      
Large-cap90
 23
 67
 —
Small-cap33
 33
 —
 —
International190
 —
 190
 —
Commingled debt273
 —
 273
 —
Debt securities:
      
U.S. Treasury and U.S. government sponsored agency192
 189
 3
 —
Corporate231
 —
 231
 —
International government1
 —
 1
 —
Other3
 —
 3
 —
Alternative investments:
      
Commodities28
 —
 28
 —
Real estate48
 —
 48
 —
Private equity31
 —
 —
 31
Hedge funds69
 —
 69
 —
Derivatives:
      
Interest rate swaps32
 —
 32
 —
Other5
 —
 5
 —
Talen Energy Retirement Plans Master Trust assets, at fair value$1,334

$353

$950

$31
        
Receivables and payables, net (a)(31)      
401(h) accounts restricted for other postretirement benefit obligations(29)      
Total Talen Energy Retirement Plans Master Trust pension assets$1,274
      
(a)Receivables and payables represent amounts for investments sold/purchased, but not yet settled along with interest and dividends earned, but not yet received.

329
108
     December 31, 2012 December 31, 2011
        Fair Value Measurements Using    Fair Value Measurements Using
     Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
Alternative investments:                        
  Commodities   59       59                
  Real estate   93       93       85       85    
  Private equity   75          75    45          45 
  Hedge funds   125       125       92       92    
Derivatives:                        
  Interest rate swaps and swaptions   36       36       20       20    
  Other   2       2       5       5    
Insurance contracts   42          42             
Receivables   55    29    26       50    31    19    
Payables   (66)   (55)   (11)      (48)   (40)   (8)   
Total PPL Services Corporation Master Trust assets   4,041    1,262    2,633    146    2,553    973    1,528    52 
401(h) account restricted for other                        
 postretirement benefit obligations   (102)   (32)   (66)   (4)   (26)   (10)   (16)   
Fair value - PPL Services Corporation Master                        
 Trust pension assets   3,939    1,230    2,567    142    2,527    963    1,512    52 
                            
(PPL, LKE and LG&E)                        
                            
LG&E and KU Energy LLC Pension Trusts                        
Cash and cash equivalents               122    122       
Equity securities:                        
  U.S.:                        
   Large-cap               220       220    
   Commingled debt               65       65    
  International               106    44    62    
Debt securities:                        
  U.S. Treasury               97    97       
  Corporate               342       342    
Derivatives:                        
  Total return swaps               4       4    
Insurance contracts               46          46 
Total LG&E and KU Energy LLC                        
 Pension Trusts assets               1,002    263    693    46 
401(h) account restricted for other                        
 postretirement benefit obligations               (58)   (13)   (45)   
Fair value - LG&E and KU Energy LLC                        
 Pension Trusts pension assets               944    250    648    46 
                            
Fair value - total U.S. pension plans $ 3,939  $ 1,230  $ 2,567  $ 142  $ 3,471  $ 1,213  $ 2,160  $ 98 

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A reconciliation of U.S. pension trustthe Master Trust assets classified as Level 3 at December 31, 2012 is as follows:     

      Residential/               
      commercial              
      backed Corporate Private Insurance Other   
      securities debt equity contracts Debt Total
                       
Balance at beginning of period    $ 7  $ 45  $ 46     $ 98 
 Actual return on plan assets                  
   Relating to assets still held                  
    at the reporting date      1    10    3       14 
   Relating to assets sold during the period      2             2 
 Purchases, sales and settlements $ 1    21    20    (7)      35 
 Transfers from level 2 to level 3             $ 1    1 
 Transfers from level 3 to level 2      (4)            (4)
Balance at end of period $ 1  $ 27  $ 75  $ 42  $ 1  $ 146 

A reconciliation of U.S. pension trust assets classified as Level 3 at December 31, 20112015 is as follows:
330
 
Private
equity
Balance at beginning of period$—
Acquisitions (a)35
Purchases, sales and settlements(4)
Balance at end of period$31
      Residential/               
      commercial              
      backed Corporate Private Insurance     
      securities debt equity contracts Other Total
                       
Balance at beginning of period    $ 6  $ 10  $ 47     $ 63 
 Actual return on plan assets                  
   Relating to assets still held                  
    at the reporting date      (4)   8    3       7 
 Purchases, sales and settlements      5    27    (4)      28 
Balance at end of period    $ 7  $ 45  $ 46     $ 98 

(PPL, PPL Energy Supply, LKE and LG&E)
(a)Transferred from a master trust maintained by PPL.

The fair value measurements of cash and cash equivalents are based on the amounts on deposit.

The market approach is used to measure fair value of equity securities. The fair value measurements of equity securities (excluding commingled funds), which are generally classified as Level 1, are based on quoted prices in active markets. These securities represent actively and passively managed investments that are managed against various equity indices.

Investments in commingled equity and debt funds are categorized as equity securities.  These investmentssecurities and are classified as Level 2, except for exchange-traded funds, which are classified as Level 1 based on quoted prices in active markets.2. The fair value measurements for Level 2 investments are based on firm quotes of net asset values per share, which are not considered obtained from a quoted price in an active market. For theInvestments in commingled equity funds these securities represent investmentsinclude funds that are measured against the Russell 1000 Growth Index, the Russell 1000 Index, the Russell 3000 Indexinvest in U.S. and the MSCI EAFE Index.  Commingledinternational equity securities. Investments in commingled debt funds are describedinclude funds that invest in greater detaila diversified portfolio of emerging market debt obligations, as well as funds that invest in the following discussion of debtinvestment grade long-duration fixed-income securities.

The fair value measurements of debt securities are generally based on evaluated pricesevaluations that reflect observable market information, such as actual trade information for identical securities or for similar securities, adjusted for observable differences. DebtThe fair value of debt securities areis generally measured using a market approach, including the use of matrix pricing.pricing models which incorporate observable inputs. Common inputs include reported trades;benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments. When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as benchmark yields, credit valuation adjustments, referencepayment data, from market research publications, monthly payment data,future predicted cash flows, collateral performance and new issue data. For the PPL Services Corporation Master Trust, these securities represent investments in securities issued by U.S. Treasury and U.S. government sponsored agencies; investments securitized by residential mortgages, auto loans, credit cards and other pooled loans; investments in investment grade and non-investment grade bonds issued by U.S. companies across several industries;industries and investments in debt securities issued by foreign governments and corporations; and exchange traded funds as well as commingled fund investments.  Investments in commingled funds include a fund that invests in a diversified portfolio of emerging market debt obligations that is measured against the JP Morgan EMBI Global Diversified Index, as well as funds that invest in investment grade long duration fixed income securities that are measured against the Barclays Long A or Better Index.  During the first ten months of 2011 for the LG&E and KU Energy LLC Pension Trusts, debt securities within commingled trusts were measured against the Barclays Aggregated Bond Index and the Barclays U.S. Government/Credit Long Index.  During the last two months of 2011, the debt securities for the LG&E and KU Energy LLC Pension Trusts were transitioned to debt securities similar to those within the PPL Services Corporation Master Trust.  The debt securities, excluding those in commingled funds, held by the PPL Services Corporation Master Trust at December 31, 2012 have a weighted-average coupon of 3.49% and a weighted-average maturity of 21 years.corporations.

Investments in commodities represent ownership of unitsinterest of a commingled fund that is invested asin a long-only, unleveraged portfolio of exchange-traded futures and forward contracts in tangible commodities to obtain broad exposure to all principal groups in the global commodity markets, including energies,energy, agriculture, livestock and metals (both precious and industrial) using proprietary commodity trading strategies. The fund has daily liquidityRedemptions can be made the 15th calendar day and last calendar day of the month with a specified notification period. The fund's fair value is based upon a unit value as calculated by the fund's trustee.administrator.

Investments in real estate represent an investment in a partnership whose purpose is to manage investments in core U.S. real estate properties diversified geographically and across major property types (e.g., office, industrial, retail, etc.). The manager is focused on properties with high occupancy rates with quality tenants. This results in a focus on high income and stable cash flows with appreciation being a secondary factor. Core real estate generally has a lower degree of leverage when compared with more speculative real estate investing strategies. The partnership has limitations on the amounts that may be redeemed based on available cash to fund redemptions. Additionally, the general partner may decline to accept redemptions when necessary to avoid adverse consequences for the partnership, including legal and tax implications, among others. The fair value of the investment is based upon a partnership unit value.
331

Investments in private equity represent interests in partnerships in multiple early-stage venture capital funds and private equity fund of funds that use a number of diverse investment strategies. FourTwo of the partnerships have limited lives of ten years, while the fifththird has a life of 15 years, after which liquidating distributions will be received. Prior to the end of each partnership's life, the investment cannot be redeemed with the partnership; however, the interest may be sold to other parties, subject to the general partner's approval. The PPL Services Corporation Master Trust has unfunded commitments of $73$12 million that may be required during the lives of the partnerships. Fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.

Investments in hedge funds represent investments in three hedge fund of funds. Hedge funds seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver

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positive returns under allmost market conditions. Major investment strategies for the hedge fund of funds include long/short equity, market neutral, distressed debt, and relative value. Generally, shares may be redeemed on 90within 60 to 95 days with prior written notice. The funds are subject to short term lockups and have limitations on the amount that may be withdrawn based on a percentage of the total net asset value of the fund, among other restrictions. All withdrawals are subject to the general partner's approval. The fair value for two of the funds has been estimated using the net asset value per share and the third fund's fair value is based on an ownership interest in partners' capital to which a proportionate share of net assets is attributed.

The fair value measurements of derivative instruments utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs. In certain instances, these instruments may be valued using models, including standard option valuation models and standard industry models. These securitiesinstruments primarily represent investments ininclude interest rate swaps, and swaptions (the option to enter into an interest rate swap) which are valued based on the swap details, such as swap curves, notional amount, index and term of index, reset frequency volatility and payer/receiver credit ratings.

Receivables/payables classified as Level 1 represent investments sold/purchased but not yet settled.  Receivables/payables classified as Level 2 represent interest and dividends earned but not yet received and costs incurred but not yet paid.

Insurance contracts, classified as Level 3, represent an investment in an immediate participation guaranteed group annuity contract.  The fair value is based on contract value, which represents cost plus interest income less distributions for benefit payments and administrative expenses.

Plan Assets - U.S. Other Postretirement Benefit Plans(PPL and LKE)

PPL'sPrior to the spinoff from PPL, the other postretirement benefit plan assets were invested by PPL in VEBA trusts and LKE'sa 401(h) account, maintained by PPL.

The investment strategy with respect to its other postretirement benefit obligations is to fund VEBA trusts and/or 401(h) accounts with voluntary contributions, when appropriate, and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the PPL Services Corporation Master Trust, in 2012 and LG&E and KU Energy LLC Pension Trusts in 2011 discussed in Plan Assets - U.S. Pension Plans above, PPL's and LKE's other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities, but treated by PPL and LKE as debt securities for asset allocation and target allocation purposes. Ownership interests in commingled money market funds that invest entirely in money market securities are classified as equity securities, but treated by PPL and LKE as cash and cash equivalents for asset allocation and target allocation purposes. The asset allocation for the VEBA trusts and the target allocation, by asset class, at December 31 are detailed below.

    Target Asset
  Percentage of plan assets AllocationPercentage of plan assetsTarget Asset Allocation
 2012  2011  2012 2015 2015
Asset ClassAsset Class         
U.S. Equity securitiesU.S. Equity securities  46%  41% 45%53% 45%
Debt securities (a)  51%  53% 50%
Cash and cash equivalents (b)   3%   6%  5%
Total   100%   100%   100%
Debt securities46% 50%
Cash and cash equivalents1% 5%
Total100% 100%

(a)Includes commingled debt funds and debt securities.
(b)Includes commingled money market fund.
332
The fair value of assets in the U.S. other postretirement benefit plans by asset class and level within the fair value hierarchy was:

     December 31, 2012 December 31, 2011
        Fair Value Measurement Using    Fair Value Measurement Using
     Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
U.S. Equity securities:                        
  Large-cap $ 145     $ 145     $ 126     $ 126    
  Commingled debt   119       119       121       121    
  Commingled money market funds   13  $ 13          20       20    
  Municipalities   41       41       40       40    
Receivables   1       1                
Total VEBA trust assets   319    13    306       307       307    
401(h) account assets (a)   102    32    66  $ 4    84  $ 23    61    
Fair value - U.S. other postretirement                        
 benefit plans $ 421  $ 45  $ 372  $ 4  $ 391  $ 23  $ 368    

(a)LKE's other postretirement benefit plan was invested primarily in a 401(h) account as disclosed in the PPL Services Corporation Master trust in 2012 and the LG&E and KU Energy LLC Pension Trusts in 2011.
 December 31, 2015
 Fair Value Measurement Using
 Total Level 1 Level 2 Level 3
U.S. Equity securities:
      
Large-cap$26
 $—
 $26
 $—
Commingled debt23
 —
 23
 —
Total VEBA trust assets, at fair value49
 $—
 $49
 $—
401(h) account assets29
      
Total other postretirement benefit plan assets$78
      

Investments in large-cap equity securities represent investments in a passively managed equity index fund that invests in securities and a combination of other collective funds that together trackfunds. Fair value measurements are not obtained from a quoted price in an active market but are based on firm quotes of net asset values per share as provided by the performancetrustee of the S&P 500 Index.fund. Redemptions can be made daily on this fund.

Investments in commingled debt securities represent investments in a fund that invests in a diversified portfolio of investment grade long-duration fixed income securities that are managed to track the Barclays U.S. Long Credit Index, as well as a fund that is tracked to the Barclays U.S. Long Treasury Index.securities. Redemptions can be made weekly on these funds.


Investments in commingled money market funds represent investments in a fund that invests primarily in a diversified portfolio of investment grade money market instruments, including, but not limited to, commercial paper, notes, repurchase agreements and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase.  The primary objective of the fund is a high level of current income consistent with stability of principal and liquidity.  Redemptions can be made daily on this fund.
110

Investments in municipalities represent investments in a diverse mixTable of tax-exempt municipal securities.Contents

Receivables represent interest and dividends earned but not received as well as investments sold but not yet settled.

Plan Assets - U.K. Pension Plans(PPL)

The overall investment strategy of WPD's pension plans is developed by each plan's independent trustees in its Statement of Investment Principles in compliance with the U.K. Pensions Act of 1995 and other U.K. legislation.  The trustees' primary focus is to ensure that assets are sufficient to meet members' benefits as they fall due with a longer term objective to reduce investment risk.  The investment strategy is intended to maximize investment returns while not incurring excessive volatility in the funding position.  WPD's plans are invested in a wide diversification of asset types, fund strategies and fund managers and therefore have no significant concentration of risk.  Commingled funds that consist entirely of debt securities are traded as equity units, but treated by WPD as debt securities for asset allocation and target allocation purposes.  These include investments in U.K. corporate bonds and U.K. gilts.

The asset allocation and target allocation at December 31 of WPD's pension plans are detailed below.

333
         Target Asset
   Percentage of plan assets Allocation
  2012  2011  2012 
Asset Class         
Cash and cash equivalents      5%   
Equity securities         
 U.K.   6%   14%  6%
 European (excluding the U.K.)   14%   5%  4%
 Asian-Pacific      5%  3%
 North American      5%  5%
 Emerging markets   3%   2%  5%
 Currency   2%   1%  1%
 Global Tactical Asset Allocation   18%     18%
Debt securities (a)   51%   56%  52%
Alternative investments   6%   7%  6%
 Total   100%   100%   100%

(a)Includes commingled debt funds.

The fair value of assets in the U.K. pension plans by asset class and level within the fair value hierarchy was:

     December 31, 2012 December 31, 2011
        Fair Value Measurement Using    Fair Value Measurement Using
     Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
                            
Cash and cash equivalents $ 14  $ 14        $ 313  $ 313       
Equity securities:                        
  U.K. companies   440    223  $ 217       921     $ 921    
  European companies (excluding the U.K.)   956    720    236       313       313    
  Asian-Pacific companies               312       312    
  North American companies               335       335    
  Emerging markets companies   231       231       116       116    
  Currency   127       127       31       31    
  Global Tactical Asset Allocation   1,220       1,220       25       25    
  Commingled debt:                        
   U.K. corporate bonds   593       593       699       699    
   U.K. gilts   1,664       1,664       2,109       2,109    
   U.K. index-linked gilts   1,243       1,243       744       744    
Alternative investments:                        
  Real estate   423       423       433       433    
Fair value - U.K. pension plans $ 6,911  $ 957  $ 5,954     $ 6,351  $ 313  $ 6,038    

Except for investments in real estate, the fair value measurements of WPD's pension plan assets are based on the same inputs and measurement techniques used to measure the U.S. pension plan assets described above.

Investments in U.K. equity securities represent passively managed equity index funds that are measured against the FTSE All Share Index.  Investments in European equity securities represent passively managed equity index funds that are measured against the FTSE Europe ex U.K. Index.  Investments in Asian-Pacific equity securities represent passively managed equity index funds that aim to outperform 50% FTSE Asia Pacific ex-Japan Index and 50% FTSE Japan Index.  Investments in North American equity securities represent passively managed index funds that are measured against the FTSE North America Index.  Investments in emerging market equity securities represent passively managed equity index funds that are measured against the MSCI Emerging Markets Index.  Investments in currency equity securities represent investments in unitized passive and actively traded currency funds.  The Global Tactical Asset Allocation strategy attempts to benefit from short-term market inefficiencies by taking positions in worldwide markets with the objective to profit from relative movements across those markets.

Debt securities include investment grade corporate bonds of companies from diversified U.K. industries.

Investments in real estate represent holdings in a U.K. unitized fund that owns and manages U.K. industrial and commercial real estate with a strategy of earning current rental income and achieving capital growth.  The fair value measurement of the fund is based upon a net asset value per share, which is based on the value of underlying properties that are independently appraised in accordance with Royal Institution of Chartered Surveyors valuation standards at least annually with quarterly valuation updates based on recent sales of similar properties, leasing levels, property operations and/or market conditions.  The fund may be subject to redemption restrictions in the unlikely event of a large forced sale in order to ensure other unit holders are not disadvantaged.
334
Expected Cash Flows - U.S. Defined Benefit Plans(PPL)

PPL's U.S.Talen Energy Supply's defined benefit pension plans have the option to utilize available prior year credit balances to meet current and future contribution requirements. However, PPL contributed $394Talen Energy expects to contribute $40 million to its U.S.defined benefit pension plans in January 2013.2016.

PPL sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets.  PPL expects to make approximately $7 million of benefit payments under these plans in 2013.

PPLTalen Energy is not required to make contributions to its other postretirement benefit plans but has historically funded these plans in amounts equal to the postretirement benefit costs recognized.  Continuation of this past practice would cause PPL to contribute $24 million to its other postretirement benefit plans in 2013.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid and the following federal subsidy payments are expected to be received by the separate plan trusts.

     Other Postretirement
        Expected
     Benefit Federal
   Pension Payment Subsidy
          
2013  $ 196  $ 49  $ 1 
2014    206    53    1 
2015    219    55    1 
2016    232    58    1 
2017    249    60    1 
2018-2022   1,475    333    3 

(PPL Energy Supply)

The PPL Montana pension plan has the option to utilize available prior year credit balances to meet current and future contribution requirements.  Therefore, no contributions are expected for 2013.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the separate plan trusts.

     Other
  Pension Postretirement
       
2013  $ 4  $ 1 
2014    5    2 
2015    6    2 
2016    6    2 
2017    7    2 
2018-2022   48    12 

(LKE)

LKE's defined benefit plans have the option to utilize available prior year credit balances to meet current and future contribution requirements.  However, LKE contributed $150 million to its pension plans in January 2013.

LKE sponsors various non-qualified supplemental pension plans for which no assets are segregated from corporate assets.  LKE expects to make $3 million of benefit payments under these plans in 2013.

LKE is not required to make contributions to its other postretirement benefit plan but has historically funded this plan in amounts equal to the postretirement benefit costs recognized.  Continuation of this past practice would cause LKE to contribute $12 million to its other postretirement benefit plan in 2013.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid and the following federal subsidy payments are expected to be received by the separate plan trusts.
335
     Other Postretirement
        Expected
     Benefit Federal
   Pension Payment Subsidy
          
2013  $ 55  $ 13  $ 1 
2014    55    13    
2015    58    14    1 
2016    60    14    
2017    65    14    1 
2018 - 2022   399    77    2 

(LG&E)

LG&E's defined benefit plan has the option to utilize available prior year credit balances to meet current and future contribution requirements.  However, LG&E contributed $11 million to its pension plan in January 2013.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the separate plan trust.

   Pension
    
2013  $ 15 
2014    15 
2015    15 
2016    16 
2017    16 
2018 - 2022   95 

Expected Cash Flows - U.K. Pension Plans(PPL)

The pension plans of WPD are subject to formal actuarial valuations every three years, which are used to determine funding requirements.  Future contributions for PPL WW were evaluated in accordance with the latest valuation performed as of March 31, 2010, in respect of PPL WW's principal pension plan, to determine contribution requirements for 2013 and forward.  Future contributions for PPL WEM were evaluated in accordance with the latest valuation performed as of June 30, 2011, in respect of PPL WEM's principal pension plan, to determine contribution requirements for 2013 and forward.  WPD expects to make contributions of approximately $136 million in 2013.  PPL WW and PPL WEM are currently permitted to recover in rates approximately 75% of their deficit funding requirements for their primary pension plans.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the separate plan trusts.plans.

  Pension
    
2013  $ 379 
2014    385 
2015    393 
2016    400 
2017    406 
2018-2022   2,141 
 Pension Other Postretirement Benefit Payment
2016$75
 $2
201781
 3
201887
 5
201992
 7
202098
 9
2021-2025538
 63

Savings Plans(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Substantially all employees of PPL's domestic subsidiariesTalen Energy are eligible to participate in deferred savings plans (401(k)s). Employer contributions to the plans were:were $16 million in 2015, $14 million in 2014 and $12 million in 2013.

  2012  2011  2010 
          
PPL $ 36  $ 31  $ 23 
PPL Energy Supply   12    11    10 
PPL Electric   5    5    4 
336
     Successor  Predecessor
          Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
                 
LKE $12  $11  $2   $9 
LG&E  6   5   1    4 
KU  6   6   1    4 

The increase for PPL in 2012 and 2011 is primarily the result of PPL's acquisition of LKE and the employer contributions related to the employees of that company and its subsidiaries under their existing plans.

(PPL, PPL Energy Supply and PPL Electric)

Employee Stock Ownership Plan

Certain PPL subsidiaries sponsor a non-leveraged ESOP in which domestic employees, excluding those of PPL Montana, LKE and the mechanical contractors, are enrolled on the first day of the month following eligible employee status.  Dividends paid on ESOP shares are treated as ordinary dividends by PPL.  Under existing income tax laws, PPL is permitted to deduct the amount of those dividends for income tax purposes and to contribute the resulting tax savings (dividend-based contribution) to the ESOP.

The dividend-based contribution is used to buy shares of PPL's common stock and is expressly conditioned upon the deductibility of the contribution for federal income tax purposes.  Contributions to the ESOP are allocated to eligible participants' accounts as of the end of each year, based 75% on shares held in existing participants' accounts and 25% on the eligible participants' compensation.

Compensation expense for ESOP contributions was $8 million in 2012, 2011 and 2010.  These amounts were offset by the dividend-based contribution tax savings and had no impact on PPL's earnings.

PPL shares within the ESOP outstanding at December 31, 2012 were 7,857,222, or 1% of total common shares outstanding, and are included in all EPS calculations.

Separation Benefits

Certain PPLTalen Energy Supply and certain subsidiaries provide separation benefits to eligible employees. These benefits may be provided in the case of separations due to performance issues, loss of job related qualifications or organizational changes. Until December 1, 2012, certainGenerally, applicable employees separated wereare eligible for cash severance payments, outplacement services accelerated stock award vesting, continuation of group health and welfare coverage, and enhanced pension and postretirement medical benefits.  As of December 1, 2012, separation benefits for certain employees were changed to eliminate accelerated stock award vesting and enhanced pension and postretirement medical benefits.  Also, the continuation of group health and welfare coverage was replaced with a single sum payment approximating the dollar amount of premium payments that would be incurred for continuation of group health and welfare coverage. Separation benefits for certain bargaining unit employees also include enhanced pension and postretirement medical benefits. Separation benefits are recorded when such amounts are probable and estimable.

See Note 1 for a discussion of separation benefits related to the spinoff and Note 11 for a discussion of separation benefits related to the one-time voluntary retirement window offered in 2014 to certain bargaining unit employees as part of the new three-year labor agreement with IBEW local 1600. Separation benefits were not significant in 2012 and 2010.2013.


See Note 10 for separation benefits recorded in 2011 in connection with a reorganization following the acquisition of WPD Midlands.
111

(PPL, PPL Energy Supply, PPL Electric and LKE)

Health Care Reform

In March 2010, Health Care Reform was signed into law.  Many provisionsTable of Health Care Reform do not take effect for an extended period of time, and most will require the publication of implementing regulations and/or issuance of program guidelines.
Beginning in 2013, provisions within Health Care Reform eliminate the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage.  As a result, in 2010:

·PPL recorded income tax expense of $8 million; and
·PPL Energy Supply recorded income tax expense of $5 million.

Other provisions within Health Care Reform that apply to PPL and its subsidiaries include:

·an excise tax, beginning in 2018, imposed on high-cost plans providing health coverage that exceeds certain thresholds;
·a requirement to extend dependent coverage up to age 26; and
·broadening the eligibility requirements under the Federal Black Lung Act.

PPL and its subsidiaries have evaluated the provisions of Health Care Reform and have included the applicable provision in the valuation of those benefit plans that are impacted.  The inclusion of the various provisions of Health Care Reform did not have a material impact on the financial statements.  PPL and its subsidiaries will continue to monitor the potential impact of any changes to the existing provisions and implementation guidance related to Health Care Reform on their benefit programs.10. Jointly Owned Facilities

14.  Jointly Owned Facilities

(PPL, PPL Energy Supply, LKE, LG&E and KU)

At December 31, 20122015 and 2011,2014 the Talen Energy Balance Sheets reflect the owned interests in the facilities listed below.

                Construction
     Ownership    Other Accumulated Work
     Interest Electric Plant Property Depreciation in Progress
PPL               
 December 31, 2012               
 Generating Plants               
  Susquehanna  90.00% $ 4,628     $ 3,530  $ 65 
  Conemaugh  16.25%   238       122    30 
  Keystone  12.34%   206       82    3 
  Trimble County Units 1 & 2  75.00%   1,279       112    43 
 Merrill Creek Reservoir  8.37%    $ 22    15    
                  
 December 31, 2011               
 Generating Plants               
  Susquehanna  90.00% $ 4,608     $ 3,496  $ 42 
  Conemaugh  16.25%   233       115    14 
  Keystone  12.34%   198       69    3 
  Trimble County Units 1 & 2  75.00%   1,245       61    35 
 Merrill Creek Reservoir  8.37%    $ 22    15    

PPL Energy Supply               
 December 31, 2012               
 Generating Plants               
  Susquehanna  90.00% $ 4,628     $ 3,530  $ 65 
  Conemaugh  16.25%   238       122    30 
  Keystone  12.34%   206       82    3 
 Merrill Creek Reservoir  8.37%    $ 22    15    
                  
 December 31, 2011               
 Generating Plants               
  Susquehanna  90.00% $ 4,608     $ 3,496  $ 42 
  Conemaugh  16.25%   233       115    14 
  Keystone  12.34%   198       69    3 
 Merrill Creek Reservoir  8.37%    $ 22    15    
338
                Construction
     Ownership    Other Accumulated Work
     Interest Electric Plant Property Depreciation in Progress
LKE                
 December 31, 2012               
 Generating Plants               
  Trimble County Unit 1  75.00% $ 304     $ 33  $ 10 
  Trimble County Unit 2  75.00%   975       79    33 
                  
 December 31, 2011               
 Generating Plants               
  Trimble County Unit 1  75.00% $ 297     $ 19  $ 11 
  Trimble County Unit 2  75.00%   948       42    24 
                  
LG&E               
 December 31, 2012               
 Generating Plants               
  E.W. Brown Units 6-7  38.00% $ 40     $ 5    
  Paddy's Run Unit 13 & E.W. Brown Unit 5  53.00%   46       3    
  Trimble County Unit 1  75.00%   304       33  $ 10 
  Trimble County Unit 2  14.25%   198       14    13 
  Trimble County Units 5-6  29.00%   29       2    
  Trimble County Units 7-10  37.00%   68       6    2 
  Cane Run Unit 7 CCGT  22.00%            16 
                  
 December 31, 2011               
 Generating Plants               
  E.W. Brown Units 6-7  38.00% $ 39     $ 3    
  Paddy's Run Unit 13 & E.W. Brown Unit 5  53.00%   44       2  $ 5 
  Trimble County Unit 1  75.00%   297       19    11 
  Trimble County Unit 2  14.25%   190       7    7 
  Trimble County Units 5-6  29.00%   31       1    
  Trimble County Units 7-10  37.00%   64       4    1 
KU                
 December 31, 2012               
 Generating Plants               
  E.W. Brown Units 6-7  62.00% $ 64     $ 7  $ 1 
  Paddy's Run Unit 13 & E.W. Brown Unit 5  47.00%   42       2    
  Trimble County Unit 2  60.75%   777       65    20 
  Trimble County Units 5-6  71.00%   70       4    
  Trimble County Units 7-10  63.00%   116       10    2 
  Cane Run Unit 7 CCGT  78.00%            53 
                  
 December 31, 2011               
 Generating Plants               
  E.W. Brown Units 6-7  62.00% $ 64     $ 5    
  Paddy's Run Unit 13 & E.W. Brown Unit 5  47.00%   39       2  $ 4 
  Trimble County Unit 2  60.75%   758       35    17 
  Trimble County Units 5-6  71.00%   66       2    4 
  Trimble County Units 7-10  63.00%   109       6    5 
 Ownership Interest Electric Plant Other Property Accumulated Depreciation Construction Work in Progress
December 31, 2015         
Generating Plants         
Susquehanna90.00% $4,791
 $—
 $3,639
 $148
Conemaugh16.25% 326
 —
 156
 7
Keystone12.34% 218
 —
 111
 3
Colstrip Units 1 & 250.00% 48
 —
 5
 2
Colstrip Units 330.00% 30
 —
 2
 3
Merill Creek Reservoir8.37% —
 22
 16
 —
          
December 31, 2014         
Generating Plants         
Susquehanna90.00% $4,746
 $—
 $3,591
 $117
Conemaugh16.25% 330
 —
 141
 2
Keystone12.34% 213
 —
 102
 2
Colstrip Units 1 & 250.00% 16
 —
 4
 3
Colstrip Unit 330.00% 16
 —
 2
 2
Merill Creek Reservoir8.37% —
 22
 15
 —

Each subsidiary owning these interests provides its own funding for its share of the facility. Each receives a portion of the total output of the generating plants equal to its percentage ownership. The share of fuel and other operating costs associated with the plants is included in the corresponding operating expenses on the Statements of Income.

In addition to the interests mentioned above, at December 31, 2012 and 2011, PPL Montana has a 50% leasehold interest in Colstrip Units 1 and 2 and a 30% leasehold interest in Colstrip Unit 3 under operating leases.  See Note 11 for additional information.  At December 31, 2012 and 2011, NorthWestern owned a 30% interest in Colstrip Unit 4.  PPLTalen Montana and NorthWestern have a sharing agreement that governs each party's responsibilities and rights relating to the operation of Colstrip Units 3 and 4. Under the terms of that agreement, each party is responsible for 15% of the total non-coal operating and construction costs of Colstrip Units 3 and 4, regardless of whether a particular cost is specific to Colstrip Unit 3 or 4, and is entitled to take up to the same percentage of the available generation from Units 3 and 4.

339
15.  Commitments11.  Commitments and Contingencies

Energy Purchases, EnergyPurchase and Sales and Other Commitments

Energy Purchase Commitments

(PPL and PPLTalen Energy Supply)

PPL Energy Supply enters into long-term energy and energy related contracts which include commitments to purchase:

Maximum
Maturity
Contract TypeDate
Fuels (a)2023 
Limestone2030 
Natural Gas Storage2015 
Natural Gas Transportation2032 
Power, excluding wind2017 
RECs2038 
Wind Power2027 
 Contract Type
 Fuels (a) Limestone Natural Gas Storage Natural Gas Transportation Power, excluding wind RECs Wind Power
Maximum Maturity Date2027 2030 2026 2034 2021 2020 2027

(a)PPL Energy Supply enters into long-term purchase contracts to supply the coal requirements for its coal-fired generation facilities.  As a result of lowerdepressed wholesale market prices for electricity and natural gas prices,gas. Talen Energy has experienced a shift in the dispatching of its generation fleet from coal-fired to combined-cycle natural gas-fired generation. This reduction in coal-fired generation output has resulted in a surplus of coal unit utilization has decreased.inventory at certain of Talen Energy's Pennsylvania plants. To mitigate the risk of exceeding available coal storage, PPLoversupply, Talen Energy Supply incurred pre-tax charges of $29$41 million during 20122015 in connection with an agreement to reduce its 2012 and 20132015 through 2018 contracted coal deliveries. These charges were recorded to "Fuel" on the Statement of Income.

(PPL, LKE, LG&E and KU)

LG&E and KU enter into purchase contracts to supply the coal and natural gas requirements for generation facilities and LG&E's gas supply operations.  These contracts include the following commitments:

Maximum
Maturity
Contract TypeDate
Coal2017 
Coal Transportation and Fleeting Services2023 
Natural Gas Storage2013 
Natural Gas Transportation2024 

LG&E and KU have a power purchase agreement with OVEC expiring in June 2040.  Pursuant to the OVEC power purchase contract, LG&E and KU are responsible for their pro-rata share of certain obligations of OVEC under defined circumstances.  These potential liabilities include unpaid OVEC indebtedness as well as shortfall amounts in certain excess decommissioning costs and other post-employment and post-retirement benefit costs other than pension.  LKE's proportionate share of OVEC's outstanding debt was $135 million at December 31, 2012, consisting of LG&E's share of $93 million and KU's share of $42 million.  Future obligations for power purchases from OVEC are unconditional demand payments, comprised of annual minimum debt service payments, as well as contractually required reimbursement of plant operating, maintenance and other expenses as follows:

  LG&E KU Total
          
2013  $ 21  $ 9  $ 30 
2014    21    9    30 
2015    21    9    30 
2016    22    10    32 
2017    22    10    32 
Thereafter   612    272    884 
  $ 719  $ 319  $ 1,038 

In addition, LG&E and KU had total energy purchases under the OVEC power purchase agreement for the periods ended as follows:
340
  Successor  Predecessor
       Two Months  Ten Months
  Year Ended Year Ended Ended  Ended
  December 31, December 31, December 31,  October 31,
  2012  2011  2010   2010 
              
LG&E $ 20  $ 22  $4   $17 
KU   9    10   2    7 
Total $ 29  $ 32  $6   $24 

(PPL and PPL Electric)

In 2009, the PUC approved PPL Electric's procurement plan for the period January 2011 through May 2013.  To date, PPL Electric has conducted all of its planned competitive solicitations.  The solicitations include a mix of long-term and short-term purchases, ranging from five months to ten years, to fulfill PPL Electric's obligation to provide for customer supply as a PLR.  In May 2012, PPL Electric filed a plan with the PUC to purchase its electricity supply for default customers for the period June 2013 through May 2015.  The PUC subsequently approved PPL Electric's plan on January 24, 2013.  The approved plan proposes that PPL Electric procure this electricity through competitive solicitations conducted twice each plan year beginning in April 2013.

(PPL Electric)

See Note 16 for information on the power supply agreements between PPL EnergyPlus and PPL Electric.

Energy SalesSale Commitments

(PPL and PPL Energy Supply)

In connection with its marketing activities or hedging strategystrategies for its power plants, PPLTalen Energy Supply has entered into long-term power sales contracts that extend into 2019, excluding long-term renewable energy agreements that extend into 2038.2020.


(PPL Energy Supply)
112

See Note 16 for information on the power supply agreements between PPL EnergyPlus and PPL Electric.

PPL Montana Hydroelectric License Commitments(PPL and PPL Energy Supply)

PPL Montana owns and operates 11 hydroelectric facilities and one storage reservoir licensed by the FERC under long-term licenses pursuant to the Federal Power Act.  Pursuant to Section 8(e)Table of the Federal Power Act, the FERC approved the transfer from Montana Power to PPL Montana of all pertinent licenses in connection with the Montana Asset Purchase Agreement.

The Kerr Dam Project license (50-year term) was issued by the FERC jointly to Montana Power and the Confederated Salish and Kootenai Tribes of the Flathead Nation in 1985, and requires PPL Montana (as successor licensee to Montana Power) to hold and operate the project for at least 30 years (to 2015).  Between 2015 and 2025, the tribes have the option to purchase, hold and operate the project for the remainder of the license term, which expires in 2035.  While the tribes have indicated their intent to exercise the option at the earliest possible date, PPL Montana cannot predict if and when this option will be exercised.  The license also requires PPL Montana to continue to implement a plan to mitigate the impact of the Kerr Dam on fish, wildlife and their habitats.  Under this arrangement, PPL Montana has a remaining commitment to spend $6 million between 2013 and 2015, in addition to the annual rent it pays to the tribes.

PPL Montana entered into two Memoranda of Understanding (MOUs) with state, federal and private entities related to the issuance in 2000 of the FERC renewal license for the nine dams comprising the Missouri-Madison project.  The MOUs are periodically updated and renewed and require PPL Montana to implement plans to mitigate the impact of its projects on fish, wildlife and their habitats, and to increase recreational opportunities.  The MOUs were created to maximize collaboration between the parties and enhance the possibility to receive matching funds from relevant federal agencies.  Under these arrangements, PPL Montana has a remaining commitment to spend $30 million between 2013 and 2040.

Legal Matters

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)Legal Proceedings

PPLTalen Energy is involved in the following legal proceedings, claims and litigation.  Talen Energy believes that it has meritorious defenses in connection with its subsidiaries are involved incurrent legal proceedings, claims and litigation, and it intends to vigorously contest each of them. However, there can be no assurance that it will be successful in the ordinary course of business.  PPL and its subsidiaries cannot predict the outcome of such matters, or whether such matters may result in material liabilities, unless otherwise noted.efforts.

WKE Indemnification(PPLNo estimate of the possible loss or range of loss in excess of amounts accrued, if any, can be made at this time regarding any of the matters specifically described below because the inherently unpredictable nature of legal proceedings may be exacerbated by various factors such as ongoing discovery, significant facts that are in dispute, the stage of the proceeding and LKE)the wide range of potential outcomes for any such matter. As a result, any losses actually incurred could be substantial.

See footnote (l) to the table in "Guarantees and Other Assurances" below for information on an LKE indemnity relating to its former WKE lease, including related legal proceedings.

(PPL and PPL Energy Supply)

Montana HydroelectricSierra Club Litigation

In November 2004, PPL Montana, Avista Corporation (Avista)March 2013, the Sierra Club and PacifiCorp commenced an action for declaratory judgment in Montana First Judicial District Court seekingMEIC filed a determination that no lease payments or other compensation for their hydroelectric facilities' use and occupancy of certain riverbeds in Montana can be collected by the State of Montana.  This lawsuit followed dismissal on jurisdictional grounds of an earlier federal lawsuit seeking such compensationcomplaint in the U.S. District Court, of Montana.  The federal lawsuit alleged that the beds of Montana's navigable rivers became state-owned trust property upon Montana's admission to statehood, and that the use of them should, under a 1931 regulatory scheme enacted after all but one of the hydroelectric facilities in question were constructed, trigger lease payments for use of land beneath.  In July 2006, the Montana state court approved a stipulation by the State of Montana that it was not seeking compensation for the period prior to PPL Montana's December 1999 acquisition of the hydroelectric facilities.

Following a number of adverse trial court rulings, in 2007 Pacificorp and Avista each entered into settlement agreements with the State of Montana providing, in pertinent part, that each company would make prospective lease payments for use of the State's navigable riverbeds (subject to certain future adjustments), resolving the State's claims for past and future compensation.

Following an October 2007 trial of this matter on damages, in June 2008, the Montana District Court awarded the State retroactive compensation of approximately $35 million for the 2000-2006 period and approximately $6 million for 2007 compensation.  Those unpaid amounts accrue interest at 10% per year.  The Montana District Court also deferred determination of compensation for 2008 and future years to the Montana State Land Board.  In October 2008, PPL Montana appealed the decision to the Montana Supreme Court, requesting a stay of judgment and a stay of the Land Board's authority to assess compensation for 2008 and future periods.

In March 2010, the Montana Supreme Court substantially affirmed the June 2008 Montana District Court decision.  As a result, in the first quarter of 2010, PPL Montana recorded a pre-tax charge of $56 million ($34 million after tax), representing estimated rental compensation for the first quarter of 2010 and prior years, including interest.  Rental compensation was estimated for periods subsequent to 2007.  The portion of the pre-tax charge that related to prior years totaled $54 million ($32 million after tax).  The pre-tax charge recorded on the Statement of Income was $49 million in "Other operation and maintenance" and $7 million in "Interest Expense."

In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting review of this matter.  In June 2011, the U.S. Supreme Court granted PPL Montana's petition, and in February 2012 issued a decision overturning the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion.  As a result, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million ($53 million after-tax) which had been recorded prior to the U.S. Supreme Court decision.  The amount reversed was recorded on the Statement of Income as a $75 million credit to "Other operation and maintenance" and a $14 million credit to "Interest Expense." PPL Montana believes the U.S. Supreme Court decision resolves certain questions of liability in this case in favor of PPL Montana and leaves open for reconsideration by Montana courts, consistent with the findings of the U.S. Supreme Court, certain other questions.  In April 2012, the case was returned by the Montana Supreme Court to the Montana First Judicial District Court.  Further proceedings have not yet been scheduled by the District Court.  PPL Montana has concluded it is no longer probable, but it remains reasonably possible, that a loss has been incurred.  While unable to estimate a range of loss, PPL Montana believes that any such amount would not be material.
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Bankruptcy of SMGT

In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Montana.  At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure.  This contract was accounted for as NPNS by PPL EnergyPlus.

The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices.  Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract and made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract.  In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February.  In March 2012, the U.S. Bankruptcy Court for the District of Montana, issued an order approvingBillings Division against Talen Montana and the request of the SMGT trustee and PPL EnergyPlus to terminate the SMGT Contract.  As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell to other customers the electricity previously contracted to SMGT.

PPL EnergyPlus' receivable under the SMGT Contract, representing non-performance by SMGT prior to termination of the SMGT Contract, totaled approximately $21 million at December 31, 2012, which has been fully reserved.

In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding.  The total claim, including the above receivable, is approximately $375 million, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract.  No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.

PPL Energy Supply cannot predict any amount that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.

Notices of Intent to Sue Colstrip Owners

In July 2012, PPL Montana received a Notice of Intent to Sue for violations of the Clean Air Act at Colstrip Steam Electric Station (Notice) from counsel on behalf of the Sierra Club and the MEIC.  An Amended Notice was received on September 4, 2012, and a Second Amended Notice was received in October 2012.  A Supplemental Notice was received in December 2012.  The Notice, Amended Notice, Second Amended Notice, and Supplemental Notice (the Notices) were all addressed to the Owner or Managing Agent of Colstrip, and to the other Colstrip co-owners:(Colstrip) owners: Avista Corporation, Puget Sound Energy, Portland General Electric Company, NorthWestern EnergyCorporation and PacifiCorp. Talen Montana operates Colstrip on behalf of the owners. The Notice allegescomplaint alleged certain violations of the Clean Air Act, including New Source Review, Title V and opacity requirements.requirements and listed 39 separate claims for relief.  The Amended Notice alleges additional opacity violations at Colstrip, and the Second Amended Notice alleges additional Title V violations.  The Supplemental Notice includes additional New Source Review Claims.  All four notices state that Sierra Club and MEIC will request a United States District Court to imposecomplaint requested injunctive relief and civil penalties requireon average of $36,000 per day per violation, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial environmental projectmitigation projects.

In July 2013, the Sierra Club and MEIC filed an additional Notice of Intent to Sue, identifying additional plant projects that are alleged not to be in the areas affected by the alleged air pollution and require reimbursement of Sierra Club's and MEIC's costs of litigation and attorney's fees.  Undercompliance with the Clean Air Act lawsuits cannot beand, in September 2013, filed until 60 days afteran amended complaint.  The amended complaint dropped all claims regarding pre-2001 plant projects, as well as the applicable notice date.  PPL is evaluatingplaintiffs' Title V and opacity claims.  It did, however, add claims with respect to a number of post-2000 plant projects, which effectively increased the allegations set forthnumber of projects subject to the litigation by about 40.  Talen Montana and the other Colstrip owners filed a motion to dismiss the amended complaint in October 2013.  In May 2014, the court dismissed the plaintiffs' independent Best Available Control Technology claims and their Prevention of Significant Deterioration (PSD) claims for three projects, but denied the owners' motion to dismiss the plaintiffs' other PSD claims on statute of limitation grounds.  In August 2014, the Sierra Club and MEIC filed a second amended complaint.  This complaint includes the same causes of action articulated in the Noticesfirst amended complaint, but in regard to only eight projects done between 2001 and cannot2013.  In September 2014, the Colstrip owners filed an answer to the second amended complaint.  Discovery closed in the first quarter of 2015, and in April, the plaintiffs indicated they intend to pursue claims related to only four of the remaining projects. The magistrate judge entered an order on the parties' motions for summary judgment on December 31, 2015. The judgment dismissed two of the plaintiffs' four remaining claims and provided more preferable legal standards for the remaining two claims. The case has been bifurcated as to liability and remedy, and the liability trial is currently set for May 2016. A trial date with respect to remedy, if there is a finding of liability, has not been scheduled.

Notice of Intent to File Suit

In October 2014, Talen Energy received a notice letter from the Chesapeake Bay Foundation (CBF) alleging violations of the Clean Water Act and Pennsylvania Clean Streams Law at the Brunner Island generation plant.  The letter was sent to Brunner Island, LLC and the PADEP and is intended to provide notice of the alleged violations and CBF's intent to file suit in Federal court after expiration of the 60 day statutory notice period.  Among other things, the letter alleges that Brunner Island, LLC failed to comply with the terms of its National Pollutant Discharge Elimination System permit and associated regulations related to the application of nutrient credits to the facility's discharges of nitrogen into the Susquehanna River.  The letter also alleges that PADEP has failed to ensure that credits generated from nonpoint source pollution reduction activities that Brunner Island, LLC applies to its discharges meet the eligibility and certification requirements under PADEP's nutrient trading program regulations.  If a lawsuit is filed by CBF, Talen Energy would expect CBF to seek injunctive relief, monetary penalties, fees and costs of litigation.  

Montana Regional Haze

In September 2012, the EPA Region 8 developed a regional haze Federal Implementation Plan (FIP) for Montana. The final FIP assumed no additional controls for Corette or Colstrip Units 3 and 4, but proposed stricter limits for Corette and Colstrip Units 1 and 2. Talen Montana was meeting these stricter permit limits at Corette without any significant changes to operations, although other requirements led to the suspension of operations and retirement of Corette in March 2015. The stricter limits at

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Colstrip Units 1 and 2 would require additional controls to meet more stringent nitrogen oxides and sulfur dioxide limits, the cost of which could be significant. Both Talen Montana and environmental groups appealed the final FIP to the U.S. Court of Appeals for the Ninth Circuit where oral argument was heard in May 2014. On June 9, 2015, the Ninth Circuit issued a decision that vacated as arbitrary and capricious the portions of the FIP setting stricter emissions limits for Colstrip Units 1 and 2 and Corette. The Ninth Circuit upheld the EPA's decision not to require further emissions reductions at Colstrip Units 3 and 4. The Ninth Circuit opinion requires the EPA to now reissue a FIP that is consistent with the opinion.

Colstrip Wastewater Facility Administrative Order on Consent

Talen Montana is party to an Administrative Order on Consent (AOC) with the MDEQ related to operation of the wastewater facilities at the Colstrip power plant. In September 2012, Earthjustice, on behalf of Sierra Club, MEIC, and the National Wildlife Federation, filed an affidavit under Montana's Major Facility Siting Act (MFSA) that sought review of the AOC by Montana's Board of Environmental Review. Talen Montana elected to have this time predictproceeding conducted in Montana state district court, and in October 2012, Earthjustice filed a petition for review in Montana state district court in Rosebud County. This matter was stayed in December 2012 pending the outcome of this matter.separate litigation where the same environmental groups challenged the AOC in a writ of mandamus. That litigation was resolved in May 2013 when defendants Talen Montana and MDEQ won their motions to dismiss the matter, and the environmental groups did not appeal. In April 2014, Earthjustice filed successful motions for leave to amend the petition for review and to lift the stay. Talen Montana and the MDEQ responded to the amended petition and filed partial motions to dismiss in July 2014, which were denied in October 2014. Discovery closed in October 2015, summary judgment motions on behalf of all parties are pending, and a bench trial is set for April 2016.

Other

In addition to the above matters, from time-to-time in the ordinary course of its business Talen Energy may be subject to other legal proceedings, claims and litigation. While the outcome of these legal proceedings, claims and litigation is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.

Regulatory IssuesMatters

(PPL, PPL Electric, LKE, LG&ETalen Energy is subject to regulation by federal and KU)state agencies in the various regions where it conducts business, including with respect to the following matters.

See Note 6 for information on regulatory matters related to utility rate regulation.

Enactment of Financial Reform Legislation(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The Dodd-Frank Act became effective in July 2010 and includes provisions that impose derivative transaction reporting requirements and require most over-the-counter derivative transactions to be executed through an exchange and to be centrally cleared.  The Dodd-Frank Act also provides that the U.S. Commodity Futures Trading Commission (CFTC) may impose collateral and margin requirements for over-the-counter derivative transactions, as well as capital requirements for certain entity classifications.  Final rules on major provisions in the Dodd-Frank Act are being established through rulemakings.  The rulemakings are scheduled to become effective at different times beginning with the October 12, 2012 effective date of the definitional rule for the term "swap".  In particular, the CFTC's Final Rule (Final Rule), defining key terms such as "swap dealer" and "major swap participant", took effect with the effectiveness of the swap definitional rule.
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The heightened thresholds and requirements for these entity classifications set forth in the Final Rule resulted in the Registrants currently being designated neither swap dealers nor major swap participants.  The Dodd-Frank Act and its implementing regulations, however, will impose on the Registrants significant additional and costly recordkeeping and reporting requirements.  Also, the Registrants could face significantly higher operating costs or may be required to post additional collateral if they or their counterparties are subject to capital or margin requirements as ultimately adopted in the implementing regulations of the Dodd-Frank Act.  The Registrants will continue to evaluate the provisions of the Dodd-Frank Act and its implementing regulations.  At this time, the Registrants cannot predict the impact that the law or its implementing regulations will have on their businesses or operations, or the markets in which they transact business, but could incur significant costs related to compliance with the Dodd-Frank Act.

(PPL, PPL Energy Supply and PPL Electric)

New Jersey Capacity Legislation

In January 2011, New Jersey enacted a law (the Act) that intervenesTalen Energy believes would intervene in the wholesale capacity market exclusively regulated by the FERC:  S. No. 2381, 214th Leg. (N.J. 2011) (the Act).  Toto create incentives for the development of new, in-state electricelectricity generation facilities the Act implements a "long-term capacity agreement pilot program (LCAPP)."  The Act requires New Jersey utilities to pay a guaranteed fixed price for wholesale capacity, imposed by the New Jersey Board of Public Utilities (BPU), to certain new generators participating in PJM, with the ultimate costs of that guarantee to be borne by New Jersey ratepayers.  PPL believes the intent and effect of the LCAPP is to encourage the construction of new generation in New Jersey even when, under the FERC-approved PJM economic model, such new generation would not be economic.  The Act could depresshave the effect of depressing capacity prices in PJM in the short term, impacting PPL Energy Supply'swhich could impact Talen Energy's revenues, and also could harm the long-term ability of the PJM capacity market to incentencourage necessary generation investment throughout PJM.

In February 2011, the PJM Power Providers Group (P3), an organization in which PPL is a member, filed a complaint before the FERC seeking changes in PJM's capacity market rules designed to ensure that subsidized generation, such as the generation that may result from the implementation of the LCAPP, will not be able to set capacity prices artificially low as a result of their exercise of buyer market power.  In April 2011, the FERC issued an order granting in part and denying in part P3's complaint and ordering changes in PJM's capacity rules consistent with a significant portion of P3's requested changes.  Several parties have filed appeals of the FERC's order.  PPL, PPLcertain Talen Energy Supply and PPL Electric cannot predict the outcome of this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.

In addition, in February 2011, PPL,subsidiaries and several other generating companies and utilities filed a complaint in U.S. District Court in New Jersey challenging the Act on the grounds that it violates well-established principlesthe Supremacy and Commerce clauses of the U.S. Constitution and requesting relief barring implementation.  In October 2013, the U.S. District Court in New Jersey issued a decision finding the Act unconstitutional under the Supremacy Clause on the grounds that it infringes upon the FERC's exclusive authority to regulate the wholesale sale of electricity in interstate commerce.  The decision was appealed to the U.S. Court of Appeals for the Third Circuit (Third Circuit) by CPV Power Development, Inc., Hess Newark, LLC and the Commerce ClauseState of New Jersey (the Appellants). In September 2014, the Third Circuit affirmed the District Court's decision. In December 2014, the Appellants filed a petition for certioraribefore the U.S. Supreme Court. In March 2015, the U.S. Supreme Court requested the U. S. Solicitor General to submit briefs expressing its views as to the issues raised in this case. In September 2015, the U.S. Solicitor General filed a brief expressing the view of the U.S. Constitution.  In this action,United States that the plaintiffs request declaratorycase was rightly decided and injunctive relief barring implementation ofthat the Act bypetition for certiorari should be denied. Talen Energy believes, though no assurances can be given, that the Commissioners of the BPU.  In October 2011, the court denied the BPU's motion to dismiss the proceeding.  In September 2012, the U.S. District Court denied all summary judgment motions, and the litigation is continuing.  Trial is scheduled to begin in March 2013.  PPL, PPL Energy Supply and PPL Electric cannot predictproceeding may be delayed pending the outcome of the Maryland Public Service Commission (MD PSC) action described below. Based upon information currently available to it, Talen Energy cannot estimate a range of reasonably possible losses, if any, related to this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.matter.


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Maryland Capacity Order

In April 2012, the Maryland Public Service Commission (MD PSC)MD PSC ordered (Order) three electric utilities in Maryland to enter into long-term contracts to support the construction of new electricelectricity generating facilities in Maryland, specifically a 661 MW natural gas-fired combined-cycle generating facility to be owned by CPV Maryland, LLC.  PPL believes the intent and effect of the action by the MD PSC iswhich, Talen Energy believed, was to encourage the construction of new generation in Maryland even when, under the FERC-approved PJM economic model, such new generation would not be economic. The MD PSC action could depresshave the effect of depressing capacity prices in PJM in the short term, impacting PPL Energy Supply'swhich could impact Talen Energy's revenues, and also could harm the long-term ability of the PJM capacity market to encourage necessary generation investment throughout PJM.

In April 2012, PPLTalen Energy subsidiaries and several other generating companies filed a complaint in U.S. District Court (District Court) in Maryland challenging the MD PSC orderOrder on the grounds that it violates well-established principles under the Supremacy and Commerce clauses of the U.S. Constitution.  In this action, the plaintiffs requestConstitution, and requested declaratory and injunctive relief barring implementation of the orderOrder by the Commissioners of the MD PSC.  In August 2012, the court denied the MD PSC andCommissioners.  In September 2013, the District Court issued a decision finding the order unconstitutional under the Supremacy Clause on the grounds that it infringes upon the FERC's exclusive authority to regulate the wholesale sale of electricity in interstate commerce.  The decision was appealed to the U.S. Court of Appeals for the Fourth Circuit (Fourth Circuit) by CPV Maryland, LLC motions to dismiss the proceedingPower Development, Inc. and the litigation is continuing.  Trial isState of Maryland (the Appellants).  In June 2014, the Fourth Circuit affirmed the District Court's opinion and subsequently denied the Appellants' motion for rehearing. In December 2014, the Appellants filed a petition for certiorari before the U.S. Supreme Court. In March 2015, the U.S. Supreme Court requested the U.S. Solicitor General to submit briefs expressing its views as to the issues raised in this case. In September 2015, the U.S. Solicitor General filed a brief expressing the view of the United States that the case was rightly decided and that the petition for certiorari should be denied. In October 2015, the U.S. Supreme Court granted certiorari of the case, and oral arguments are scheduled for February 2016. Based upon information currently available to begin in March 2013.  PPL, PPLit, Talen Energy Supply, and PPL Electric cannot predict the outcomeestimate a range of reasonable possible losses, if any, related to this proceeding or the economic impact on their businesses or operations, or the markets in which they transact business.matter.

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Pacific Northwest Markets(PPL and PPL Energy Supply)

Through its subsidiaries, PPLTalen Energy SupplyMarketing and Talen Montana made spot market bilateral sales of power in the Pacific Northwest during the period from December 2000 through June 2001.  Several parties subsequently claimed refunds at the FERC as a result of these sales.  In June 2003, the FERC terminated proceedings to consider whether to order refunds for spot market bilateral sales made in the Pacific Northwest, including sales made by PPLTalen Montana, during the period December 2000 through June 2001.  In August 2007, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC's decision and ordered the FERC to consider additional evidence.  In October 2011, the FERC initiated proceedings to consider additional evidence.  At June 30, 2012, there were two remaining claims against PPL Energy Supply totaling $73 million.  In December 2015, the United States Court of Appeals for the Ninth Circuit affirmed the FERC's October 2011 order setting out the remand process that the FERC has followed from 2011 to the present.

In July 2012, PPLTalen Montana and the City of Tacoma, one of the two parties claiming refunds at the FERC, reached a settlement whereby PPLTalen Montana would paypaid $75 thousand to resolve the City of Tacoma's $23 million claim, $9 million of which represents interest.claim.  The settlement does not resolve the remaining claim outstanding at December 31, 2012by the City of Seattle for approximately $50 million.  Hearings before a FERC Administrative Law Judge (ALJ) regarding the City of Seattle's refund claims were completed in October 2013 and briefing was completed in January 2014.  In March 2014, the ALJ issued an initial decision denying the City of Seattle's complaint against Talen Montana.  In May 2015, the FERC issued an order affirming the ALJ's March 2014 decision, and in January 2016 the FERC denied requests for a rehearing of its order affirming the ALJ's decision. In February 2016 the City of Seattle appealed the FERC's decision to the United States Court of Appeals for the Ninth Circuit.

Although PPLTalen Energy and its subsidiaries believe they have not engaged in any improper trading or marketing practices affecting the Pacific Northwest markets, PPL and PPLTalen Energy Supply cannot predict the outcome of the above-described proceedings or whether any subsidiaries will be the subject of any additional governmental investigations or named in other lawsuits or refund proceedings.  Consequently, PPL and PPLTalen Energy Supply cannot estimate a range of reasonably possible losses, if any, related to this matter.

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

FERC Market-Based Rate Authority

In 1998, the FERC authorized LG&E, KU and PPL EnergyPlus to make wholesale sales of electric power and related products at market-based rates.  In those orders, the FERC directed LG&E, KU and PPL EnergyPlus, respectively, to file an updated market analysis within three years after the order, and every three years thereafter.  Since then, periodic market-based rate filings with the FERC have been made by LG&E, KU, PPL EnergyPlus, PPL Electric, PPL Montana and most of PPL Generation's subsidiaries.  These filings consisted of a Northwest market-based rate filing for PPL Montana and a Northeast market-based rate filing for most of the other PPL subsidiaries in PJM's region.  In June 2011, FERC approved PPL's market-based rate update for the Eastern and Western regions.  Also, in June 2011, PPL filed its market-based rate update for the Southeast region, including LG&E and KU in addition to PPL EnergyPlus.  In June 2011, the FERC issued an order approving LG&E's and KU's request for a determination that they no longer be deemed to have market power in the BREC balancing area and removing restrictions on their market-based rate authority in such region.

Currently, a seller granted FERC market-based rate authority may enter into power contracts during an authorized time period.  If the FERC determines that the market is not workably competitive or that the seller possesses market power or is not charging "just and reasonable" rates, it may institute prospective action, but any contracts entered into pursuant to the FERC's market-based rate authority remain in effect and are generally subject to a high standard of review before the FERC can order changes.  Recent court decisions by the U.S. Court of Appeals for the Ninth Circuit have raised issues that may make it more difficult for the FERC to continue its program of promoting wholesale electricity competition through market-based rate authority.  These court decisions permit retroactive refunds and a lower standard of review by the FERC for changing power contracts, and could have the effect of requiring the FERC in advance to review most, if not all, power contracts.  In June 2008, the U.S. Supreme Court reversed one of the decisions of the U.S. Court of Appeals for the Ninth Circuit, thereby upholding the higher standard of review for modifying contracts.  At this time, PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU cannot predict the impact of these court decisions on the FERC's future market-based rate authority program or on their businesses.

ElectricElectricity - Reliability Standards

The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk power system.  The FERC oversees this process and independently enforces the Reliability Standards.

The Reliability Standards have the force and effect of law and apply to certain users of the bulk power electricity system, including electric utility companies, generators and marketers.  Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations.


LG&E, KU, PPL Electric and certain subsidiaries
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Talen Energy Supply monitor theirmonitors its subsidiaries' compliance with the Reliability Standards and continue to self-reportself-reports potential violations of certain applicable reliability requirements and submit accompanying mitigation plans, as required.  The resolution of a number of potential violations is pending.  Any Regional Reliability Entity (including RFC or SERC) determination concerning the resolution of violations of the Reliability Standards remains subject to the approval of the NERC and the FERC.
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In the course of implementing their programs to ensure compliance with the Reliability Standards by those PPL affiliatesTalen Energy subsidiaries subject to the standards, certain other instances of potential non-compliance may be identified from time to time.  The Registrants cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any, other than the amounts currently recorded.

In October 2012, the FERC issued a Notice of Proposed Rulemaking (NOPR) concerning Reliability Standards for Geomagnetic Disturbances.  The FERC proposes to direct NERC to submit for approval Reliability Standards that address the impact of geomagnetic disturbances on the reliable operation of the bulk-power system, including one or more measures to protect against damage to the bulk-power system, such as the installation of equipment that blocks geomagnetically induced currents on implicated transformers.  If the NOPR is adopted by the FERC, it is expected to require the Registrants either or both to make significant expenditures in new equipment or modifications to their facilities.  The Registrants are unable to predict whether the NOPR will be adopted as proposed by the FERC or the amount of any expenditures that may be required as a result of the adoption of any Reliability Standards for geomagnetic disturbances.

Settled Litigation (PPL and PPLTalen Energy Supply)

Spent Nuclear Fuel Litigation

In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant.  PPL Susquehanna recorded credits totaling $56 million to "Fuel" on the Statement of Income in 2011 to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant.  The amounts recorded through September 2011 cover costs incurred from 1998 through December 2010.  PPL Susquehanna is eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that are incurred through December 31, 2013.  In exchange, PPL Susquehanna has waived any claims against the United States government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna plan through December 31, 2013.

Environmental Matters - Domestic

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Due to the environmental issues discussed below or other environmental matters, it may be necessary for the Registrants to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies or courts.  In addition, legal challenges to new environmental permits or rules add to the uncertainty of estimating the future cost impact of these permits and rules.

LG&E and KU are entitled to recover, through the ECR mechanism, certain costs of complying with the Clean Air Act as amended and those federal, state, or local environmental requirements which apply to coal combustion wastes and by-products from facilities utilized for production of energy from coal in accordance with their approved compliance plans.  Costs not covered by the ECR for LG&E and KU and all such costs for PPL Electric are subject to rate recovery before their respective state regulatory authorities, or the FERC, if applicable.  Because PPL Electric does not own any generating plants, its exposure to environmental compliance costs is reduced.  As PPL Energy Supply is not a rate regulated entity, it does not have any mechanism for seeking rate recovery of environmental compliance costs.  PPL, PPL Electric, LKE, LG&E and KU can provide no assurances as to the ultimate outcome of future environmental or rate proceedings before regulatory authorities.

(PPL, PPL Energy Supply, LKE, LG&E and KU)

Air

CSAPR (formerly Clean Air Transport Rule) and CAIR

In July 2011, the EPA adopted the CSAPR, which was intended to finalize and rename the Clean Air Transport Rule (Transport Rule) proposed in August 2010.  The CSAPR replaced the EPA's previous CAIR which was invalidated by the U.S. Court of Appeals for the District of Columbia Circuit (the Court) in July 2008.  CAIR subsequently was effectively reinstated by the Court in December 2008, pending finalization of the Transport Rule.  Like CAIR, CSAPR only applied to PPL's fossil-fueled generating plants located in Kentucky and Pennsylvania.
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In December 2011, the Court stayed implementation of the CSAPR and left CAIR in effect pending a final decision on the validity of the rule.  In August 2012, the Court issued a ruling invalidating CSAPR, remanding the rule to the EPA for further action, and leaving CAIR in place during the interim.  A further revised rule is not expected from the EPA for at least two years.
The CSAPR was meant to facilitate attainment of ambient air quality standards for ozone and fine particulates by requiring reductions in sulfur dioxide and nitrogen oxides emissions.  The CSAPR established new sulfur dioxide and nitrogen oxide emission allowance cap and trade programs that were more restrictive than previously under CAIR.  The CSAPR provided for two-phased programs of sulfur dioxide and nitrogen oxide emissions reductions, with initial reductions in 2012 and more stringent reductions in 2014.

The Kentucky fossil-fueled generating plants can meet the CAIR sulfur dioxide emission requirements by utilizing sulfur dioxide allowances (including banked allowances).  To meet nitrogen oxide standards, under the CAIR, the Kentucky companies will need to buy allowances and/or make operational changes.  LG&E and KU do not currently anticipate that the costs of meeting these reinstated CAIR requirements or standards will be significant.

PPL Energy Supply's Pennsylvania fossil-fueled generating plants can meet the CAIR sulfur dioxide emission requirements with the existing scrubbers that were placed in service in 2008 and 2009.  To meet nitrogen oxide standards, under the CAIR, PPL Energy Supply will need to buy allowances and/or make operational changes, the costs of which are not anticipated to be significant.

National Ambient Air Quality Standards

In addition to the reductions in sulfur dioxide and nitrogen oxide emissions required under the CAIR for its Pennsylvania and Kentucky plants, PPL's fossil-fueled generating plants, including those in Montana, may face further reductions in sulfur dioxide and nitrogen oxide emissions as a result of more stringent national ambient air quality standards for ozone, nitrogen oxide, sulfur dioxide and/or fine particulates.

In 2010, the EPA finalized a new one-hour standard for sulfur dioxide, and states are required to identify areas that meet those standards and areas that are in non-attainment.  For non-attainment areas, states are required to develop plans by 2014 to achieve attainment by 2017.  For areas that are in attainment or that are unclassifiable, states are required to develop maintenance plans by mid-2013 that demonstrate continued attainment.  In December 2012, the EPA issued final rules that strengthen the particulate standards.  Under the final rule, states and the EPA have until the end of 2014 to identify initial non-attainment areas, and states have until 2020 to achieve attainment status for those areas.  States can request an extension to 2025 to comply with the rule.  Until particulate matter and sulfur dioxide maintenance and compliance plans are developed, PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict which of their facilities may be located in a non-attainment area and what measures would be required to achieve attainment status.

PPL, PPL Energy Supply, LKE, LG&E and KU anticipate that some of the measures required for compliance with the CAIR, the MATS, or the Regional Haze requirements, such as upgraded or new sulfur dioxide scrubbers at some of their plants and, in the case of LG&E and KU, the previously announced retirement of coal-fired generating units at the Cane Run, Green River and Tyrone plants, will help to achieve compliance with the new one-hour sulfur dioxide standard.  If additional reductions were to be required, the financial impact could be significant.

Mercury and Other Hazardous Air Pollutants

In May 2011, the EPA published a proposed regulation providing for stringent reductions of mercury and other hazardous air pollutants.  In February 2012, the EPA published the final rule, known as the MATS, with an effective date of April 16, 2012.  The rule is being challenged by industry groups and states.  The EPA issued a proposed rule in November 2012 reconsidering limited aspects of its MATS and New Source Performance Standards (NSPS) to which PPL responded with comments.

The rule provides for a three-year compliance deadline with the potential for a one-year extension as provided under the statute.  Based on their assessment of the need to install pollution control equipment to meet the provisions of the proposed rule, LG&E and KU filed requests with the KPSC for environmental cost recovery to facilitate moving forward with plans to install environmental controls including chemical additive and fabric-filter baghouses to remove certain hazardous air pollutants.  Recovery of the cost of certain controls was granted by the KPSC in December 2011.  See Note 6 for information on LG&E's and KU's anticipated retirement of certain coal-fired electric generating units in response to this and other environmental regulations.  With the publication of the final MATS rule, LG&E and KU are currently assessing whether any revisions of their approved compliance plans will be necessary.
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With respect to PPL Energy Supply's Pennsylvania plants, PPL Energy Supply believes that certain coal-fired plants may require installation of chemical additive systems, the cost of which is not expected to be significant.  With respect to PPL Energy Supply's Montana plants, modifications to the current air pollution controls installed on Colstrip may be required, the cost of which is not expected to be significant.  For the Corette plant, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place the plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with the MATS requirements.  The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million.  Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods as higher priced sales contracts settle, adversely impacting projected cash flows.  PPL Energy Supply, LG&E and KU are continuing to conduct in-depth reviews of the MATS, including the potential implications to scrubber wastewater discharges.  See the discussion of effluent limitations guidelines and standards below.

Regional Haze and Visibility

In January 2012, the EPA proposed limited approval of the Pennsylvania regional haze State Implementation Plan (PA SIP).  That proposal would essentially approve PPL's analysis that further particulate controls at PPL Energy Supply's Pennsylvania plants are not warranted.  The limited approval does not address deficiencies of the state plan arising from the remand of the CAIR.  Previously, the EPA had determined that implementation of the CAIR requirements would meet regional haze requirements.

In 2012, the EPA finalized a rule providing that implementation of the CSAPR would also meet the Best Available Retrofit Technology (BART) requirements for sulfur dioxide and nitrogen oxides.  This rule also addresses the PA SIP deficiency arising from the CAIR remand.  However, in August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (Court) vacated and remanded the CSAPR back to the EPA for further rulemaking (as discussed above).  In September 2012, several environmental groups filed a petition for review with the Court challenging the EPA's approval of the PA SIP.  At this time, it is not known whether the EPA will reinstate its previous determination that CAIR satisfies the BART requirement or will require states to conduct source-specific BART studies.

In Montana, the EPA Region 8 developed the regional haze plan as the Montana Department of Environmental Quality declined to develop a BART state implementation plan at this time.  PPL submitted to the EPA its analyses of the visibility impacts of sulfur dioxide, nitrogen oxides and particulate emissions for Colstrip Units 1 and 2 and Corette.  PPL's analyses concluded that further reductions are not warranted, except that the EPA concurred with the installation of Separated Overfire Air (SOFA) and lime injection for Units 1 and 2.  PPL has also submitted data and analyses of various air emission control options under the rules to reduce air emissions related to the non-BART-affected emission sources of Colstrip Units 3 and 4.  The analyses show that any incremental reductions would not be cost-effective and that further analysis is not warranted.

In September 2012, the EPA issued its final Federal Implementation Plans (FIP) for the Montana regional haze rule.  The final FIP indicated that no additional controls were required for Corette or Colstrip Units 3 and 4 but proposed tighter limits for Corette and Colstrip Units 1 and 2.  PPL Energy Supply expects to meet these tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015.  See "Mercury and Other Hazardous Air Pollutants" discussion above.  Under the final FIP, Colstrip Units 1 and 2 will require additional controls, including the possible installation of an SNCR and other technology, to meet more stringent nitrogen oxide and sulfur dioxide limits.  The cost of these potential additional controls, if required, could be significant.  In November 2012, PPL filed a petition for review of the Montana Regional Haze FIP with the U.S. Court of Appeals for the Ninth Circuit.  Environmental groups have also filed a petition for review.  The two matters have been consolidated, and the parties have agreed to a briefing schedule.

LG&E and KU also submitted analyses of the visibility impacts of their Kentucky BART-eligible sources to the Kentucky Division for Air Quality (KDAQ).  Only LG&E's Mill Creek plant was determined to have a significant regional haze impact.  The KDAQ has submitted a regional haze SIP to the EPA which requires the Mill Creek plant to reduce its sulfuric acid mist emissions from Units 3 and 4, the costs of which are not expected to be significant.  After approval of the Kentucky SIP by the EPA and revision of the Mill Creek plant's air permit under Title V, LG&E intends to install sorbent injection controls at the plant to reduce sulfuric acid mist emissions.

New Source Review (NSR)

The EPA has continued its NSR enforcement efforts targeting coal-fired generating plants.  The EPA has asserted that modification of these plants has increased their emissions and, consequently, that they are subject to stringent NSR requirements under the Clean Air Act.  In April 2009, PPL received EPA information requests for its Montour and Brunner Island plants.  The requests are similar to those that PPL received in the early 2000s for its Colstrip, Corette and Martins Creek plants.  PPL and the EPA have exchanged certain information regarding this matter.  In January 2009, PPL and other
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companies that own or operate the Keystone plant in Pennsylvania received a notice of violation from the EPA alleging that certain projects were undertaken without proper NSR compliance.  In May and November 2012, PPL Montana received information requests from the EPA regarding projects undertaken during the Spring 2012 maintenance outage at Colstrip Unit 1.  In September 2012, PPL Montana received an information request from the Montana Department of Environmental Quality regarding the Unit 1 and other projects.  PPL and PPL Energy Supply cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.

Other

In addition to the regulatory matters discussed above, Talen Energy and its subsidiaries are party to other regulatory proceedings arising in August 2007, LG&E received information requests for the Mill Creek and Trimble County plants, and KU received requests for the Ghent plant, but theyordinary course of business or have received no further communications from the EPA since providing their responses.  PPL, LKE, LG&E and KU cannot predictother regulatory exposure. While the outcome of these other regulatory matters and cannot estimateproceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a rangematerial adverse effect on Talen Energy's financial condition or results of reasonably possible losses, if any.operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.

Environmental Matters

In March 2009, KU received a notice alleging that KU violated certain provisions of the Clean Air Act's rules governing NSREnvironmental Laws and prevention of significant deterioration by installing sulfur dioxide scrubbers and SCR controls at its Ghent plant without assessing potential increased sulfuric acid mist emissions.  KU contends that the work in question, as pollution control projects, was exempt from the requirements cited by the EPA.  In December 2009, the EPA issued an information request on this matter.  In September 2012, the parties reached a tentative settlement addressing the Ghent NSR matter and a September 2007 notice of violation alleging opacity violations at the plant.  A consent decree was lodged in the U.S. District Court for the Eastern District of Kentucky in December 2012.  PPL, LKE and KU cannot predict the outcome of this matter until the consent decree is entered by the Court, but currently do not expect such outcome to result in costs in excess of amounts already accrued, which amounts are not material.Regulations

If PPL subsidiaries are found to have violated NSR regulations, PPL, PPL Energy Supply, LKE, LG&E and KU would, among other things, be required to meet permit limits reflecting Best Available Control Technology (BACT) for the emissions of any pollutant found to have significantly increased due to a major plant modification.  The costs to meet such limits, including installation of technology at certain units, could be significant.

States and environmental groups also have provided notice of their intention to initiate enforcement actions and litigation alleging violations of the NSR regulations by coal-fired generating plants.  See "Legal Matters" above for information on a notice of intent to sue received in July 2012 (and amended multiple times thereafter) by PPL Montana and other owners of Colstrip.  PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict whether such actions will be brought against any of their other plants.

Colstrip and Corette Air Permits (PPL and PPL Energy Supply)

In January 2013, Earthjustice, on behalf of the Sierra Club and the MEIC filed an administrative appeal with the Board of Environmental Review, setting forth challenges to certain components of the Title V permits for Colstrip and Corette.  These challenges include: 1) the regional haze requirements should have been included in the Title V permits for Corette and Colstrip; 2) the MATS requirements should have been included in the Title V permits for Corette and Colstrip; 3) the particulate monitoring methodology is inadequate at Corette and Colstrip; and 4) sulfur dioxide monitoring is inadequate at Corette.  PPL Montana intends to participate in this proceeding and cannot predict its outcome.

On January 31, 2013, the Sierra Club and the MEIC alleged identical claims in their joint petition to the EPA, requesting that the EPA object to the MDEQ's issuance of Colstrip's and Corette's Title V permits.  PPL Montana cannot predict the outcome of this parallel matter pending before the EPA.

TC2 Air Permit (PPL, LKE, LG&E and KU)

The Sierra Club and other environmental groups petitioned the Kentucky Environmental and Public Protection Cabinet to overturn the air permit issued for the TC2 baseload generating unit, but the agency upheld the permit in an order issued in September 2007.  In response to subsequent petitions by environmental groups, the EPA ordered certain non-material changes to the permit which were incorporated into a final revised permit issued by the KDAQ in January 2010.  In March 2010, the environmental groups petitioned the EPA to object to the revised state permit.  Until the EPA issues a final ruling on the pending petition and all available appeals are exhausted, PPL, LKE, LG&E and KU cannot predict the outcome of this matter or the potential impact on the capital costs of this project, if any.
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(PPL, PPL Energy Supply, LKE, LG&E and KU)

Global Climate Change

There is concern nationally and internationally about global climate change and the possible contribution of GHG emissions including, most significantly, carbon dioxide, from the combustion of fossil fuels.  This has resulted in increased demands for carbon dioxide emission reductions from investors, environmental organizations, government agencies and the international community.  These demands and concerns have led toExtensive federal, legislative proposals, actions at regional, state and local levels, litigation relatingenvironmental laws and regulations are applicable to GHGTalen Energy's air emissions, water discharges and the EPA regulations on GHGs.management of hazardous and solid waste, as well as other aspects of its business.  In addition, many of these environmental considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost for their products or their demand for Talen Energy's services.

Greenhouse Gas Legislation

While climate change legislation was actively considered in 2009-2010, such legislation has not significantly progressed.  Since that time, although the U.S. HouseIt may be necessary for Talen Energy to modify, curtail, replace or cease operation of Representatives passed legislation attemptingcertain facilities or performance of certain operations to bar the EPA from regulating GHG emissions under the existing authority of the Clean Air Act, the Senate never took up the legislation.  The timing and elements of future federal legislation addressing GHG emission reductions are uncertain at this time.

Greenhouse Gas Regulations and Tort Litigation

As a result of the April 2007 U.S. Supreme Court decision that the EPA has authority under the Clean Air Act to regulate GHG emissions from new motor vehicles, in April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that apply beginningcomply with 2012 model year vehicles.  The EPA also clarified that this standard, beginning in 2011, authorized regulation of GHG emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act.  As a result, any new sources or major modifications to existing GHG sources causing a net significant emissions increase requires the BACT permit limits for GHGs.  The rules were challenged, and in June 2012, the U.S. Court of Appeals for the District of Columbia Circuit upheld the EPA's regulations.  In December 2012, the Court denied petitions for rehearing pertaining to the Court's June 2012 opinion.

In addition, in April 2012, the EPA proposed NSPS for carbon dioxide emissions from new coal-fired generating units, combined-cycle natural gas units, and integrated gasification combined-cycle units.  The proposal would require new coal plants to achieve the same stringent limitations on carbon dioxide emissions as the best performing new gas plants.  There presently is no commercially available technology to allow new coal plants to achieve these limitations and, as a result, the EPA's proposal would effectively preclude future construction of new coal-fired generation.  In December 2012, the U.S. Court of Appeals for the District of Columbia Circuit dismissed consolidated challenges to the NSPS holding that the proposed rule is not a final agency action.  The EPA is expected to finalize the NSPS for new sources in early 2013.

At the regional level, ten northeastern states signed a Memorandum of Understanding (MOU) agreeing to establish a GHG emission cap-and-trade program, called the Regional Greenhouse Gas Initiative (RGGI).  The program commenced in January 2009 and calls for stabilizing carbon dioxide emissions, at base levels established in 2005, from electric power plants with capacity greater than 25 MW.  The MOU also provides for a 10% reduction, by 2019, in carbon dioxide emissions from base levels.

Pennsylvania has not stated an intention to join the RGGI, but enacted the Pennsylvania Climate Change Act of 2008 (PCCA).  The PCCA established a Climate Change Advisory Committee to advise the PADEP on the development of a Climate Change Action Plan.  In December 2009, the Advisory Committee finalized its Climate Change Action Report and identified specific actions that could result in reducing GHG emissions by 30% by 2020.  Some of the proposed actions, such as a mandatory 5% efficiency improvement at power plants, could be technically unachievable.  To date, there have been no regulatory or legislative actions taken to implement the recommendations of the report.  In addition, legislation has been introduced that would, if enacted, accelerate solar supply requirements and restrict eligible solar projects to those located in Pennsylvania.  PPL and PPL Energy Supply cannot predict at this time whether this legislation will be enacted.

Eleven western states and certain Canadian provinces established the Western Climate Initiative (WCI) in 2003.  The WCI established a goal of reducing carbon dioxide emissions by 15% below 2005 levels by 2020 and developed GHG emission allocations, offsets, and reporting recommendations.  Montana was once a partner in the WCI, but by 2011 withdrew, along with several other western states.
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In November 2008, the Governor of Kentucky issued a comprehensive energy plan including non-binding targets aimed at promoting improved energy efficiency, development of alternative energy, development of carbon capture and sequestration projects,statutes, regulations and other actions to reduce GHG emissions.  In December 2009, the Kentucky Climate Action Plan Council was established to develop an action plan addressing potential GHG reductions and related measures.  To date, the state has not issued a final plan.  The impact of any such plan is not now determinable, but therequirements imposed by regulatory bodies, courts or environmental groups.  Talen Energy may incur costs to comply with the plan could be significant.

A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting plants, and the law remains unsettled on these claims.  In September 2009, the U.S. Court of Appeals for the Second Circuit in the case of AEP v. Connecticut reversed a federal district court's decision and ruled that several states and public interest groups, as well as the City of New York, could sue five electric utility companies under federal common law for allegedly causing a public nuisance as a result of their emissions of GHGs.  In June 2011, the U.S. Supreme Court overturned the lower court and held that such federal common law claims were displaced by the Clean Air Act and regulatory actions of the EPA.  In addition, in Comer v. Murphy Oil (Comer case), the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit) declined to overturn a district court ruling that plaintiffs did not have standing to pursue state common law claims against companies that emit GHGs.  The complaint in the Comer case named the previous indirect parent of LKE as a defendant based upon emissions from the Kentucky plants.  In January 2011, the Supreme Court denied a petition to reverse the Fifth Circuit's ruling.  In May 2011, the plaintiffs in the Comer case filed a substantially similar complaint in federal district court in Mississippi against 87 companies, including KU and three other indirect subsidiaries of LKE, under a Mississippi statute that allows the re-filing of an action in certain circumstances.  In March 2012, the Mississippi federal court granted defendants' motions to dismiss the state common law claims because plaintiffs had previously raised the same claims, plaintiffs lacked standing, plaintiffs' claims were displaced by the Clean Air Act, and other grounds.  In April 2012, plaintiffs filed a notice of appeal in the Fifth Circuit.  Additional litigation in federal and state courts over these issues is continuing.  PPL, LKE and KU cannot predict the outcome of this litigation or estimate a range of reasonably possible losses, if any.

In 2012, PPL's power plants emitted approximately 70 million tons of carbon dioxide compared with 74 million tons in 2011.  The totals reflect 35 million tons from PPL Generation and 35 million tons from LG&E's and KU's generating fleet.  All tons are U.S. short tons (2,000 pounds/ton).

Renewable Energy Legislation (PPL, PPL Energy Supply, LKE, LG&E and KU)

There has been interest in renewable energy legislation at both the state and federal levels.  Federal legislation on renewable energy is not expected to be introduced this year.  In Pennsylvania, bills were recently introduced in both the Senate and House amending the existing AEPS to accelerate the current solar generation obligation, but no action was taken before the end of the 2011-2012 legislative session.  Future bills are expected calling for an increase in AEPS Tier 1 (renewable resources, such as wind and solar) obligations and to create a $25 million permanent funding program for solar.  Bills have also been introduced in Montana to add hydropower as a qualified source to the renewable portfolio standard.

PPL, PPL Energy Supply, LKE, LG&E and KU believe there are financial, regulatory and logistical uncertainties related to the implementation of renewable energy mandates that will need to be resolved before the impact of such requirements on them can be estimated.  Such uncertainties, among others, include the need to provide back-up supply to augment intermittent renewable generation, potential generation over-supply that could result from such renewable generation and back-up, impacts to PJM's capacity market and the need for substantial changes to transmission and distribution systems to accommodate renewable energy sources.  These uncertainties are not directly addressed by proposed legislation.  PPL and PPL Energy Supply cannot predict at this time the effect on their merchant plants' future competitive position, results of operation, cash flows and financial position of renewable energy mandates that may be adopted, although the costs to implement and comply with any such requirements could be significant.

Water/Waste

Coal Combustion Residuals (CCRs) (PPL, PPL Energy Supply, LKE, LG&E and KU)

In June 2010, the EPA proposed two approaches to regulating the disposal and management of CCRs (as either hazardous or non-hazardous) under the Resource Conservation and Recovery Act (RCRA).  CCRs include fly ash, bottom ash and sulfur dioxide scrubber wastes.  The first approach would regulate CCRs as a hazardous waste under Subtitle C of the RCRA.  This approach would materially increase costs and result in early retirements of many coal-fired plants, as it would require plants to retrofit their operations to comply with full hazardous waste requirements for the generation of CCRs and associated waste waters through generation, transportation and disposal.  This would also have a negative impact on the beneficial use of CCRs and could eliminate existing markets for CCRs.  The second approach would regulate CCRs as a solid (non-hazardous) waste under Subtitle D of the RCRA.  This approach would mainly affect disposal and most significantly affect any wet
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disposal operations.  Under this approach, many of the current markets for beneficial uses would not be affected.  Currently, PPL expects that several of its plants in Kentucky and Montana could be significantly impacted by the requirements of Subtitle D of the RCRA, as these plants are using surface impoundments for management and disposal of CCRs.

The EPA has issued information requests on CCR management practices at numerous plants throughout the power industry as it considers whether or not to regulate CCRs as hazardous waste.  PPL has provided information on CCR management practices at most of its plants in response to the EPA's requests.  In addition, the EPA has conducted follow-up inspections to evaluate the structural stability of CCR management facilities at several PPL plants and PPL has implemented certain actions in response to recommendations from these inspections.

The EPA is continuing to evaluate the unprecedented number of comments it received on its June 2010 proposed regulations.  In October 2011, the EPA issued a Notice of Data Availability (NODA) that requests comments on selected documents that the EPA received during the comment period for the proposed regulations.  In addition, the U.S. House of Representatives in September 2012 approved a bill that was revised in the Senate to modify Subtitle D of the RCRA to provide for the proper management and disposal of CCRs and to preclude the EPA from regulating CCRs under Subtitle C of the RCRA.  This revised bill is being considered in the Senate and the prospect for passage is uncertain.

In January 2012, a coalition of environmental groups filed a 60-day notice of intent to sue the EPA for failure to perform nondiscretionary duties under RCRA, which could require a deadline for the EPA to issue strict CCR regulations.  In February 2012, two CCR recycling companies also issued a 60-day notice of intent to sue the EPA over its timeliness in issuing CCR regulations, but they requested that the EPA take a Subtitle D approach that would allow for continued recycling of CCRs.  The coalition filed its lawsuit in April 2012 and litigation is continuing.

A final rulemaking is currently expected before the end of 2015.  However, the timing of the final regulations could be accelerated by the outcome of the above litigation, which could require the EPA to issue its regulations sooner.

PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict at this time the final requirements of the EPA's CCR regulations or potential changes to the RCRA and what impact they would have on their facilities, but the financial impact could be material if regulated as a hazardous waste under Subtitle C and significant if regulated under Subtitle D.

Martins Creek Fly Ash Release (PPL and PPL Energy Supply)

In 2005, approximately 100 million gallons of water containing fly ash was released from a disposal basin at the Martins Creek plant used in connection with the operation of the plant's two 150 MW coal-fired generating units.  This resulted in ash being deposited onto adjacent roadways and fields, and into a nearby creek and the Delaware River.  PPL determined that the release was caused by a failure in the disposal basin's discharge structure.  PPL conducted extensive clean-up and completed studies, in conjunction with a group of natural resource trustees and the Delaware River Basin Commission, evaluating the effects of the release on the river's sediment, water quality and ecosystem.

The PADEP filed a complaint in Pennsylvania Commonwealth Court against PPL Martins Creek and PPL Generation, alleging violations of various state laws and regulations, including increased capital expenditures or operating and seekingmaintenance expenses, monetary fines, penalties and injunctive relief.  PPL and the PADEP have settled this matter.  The settlement also required PPL to submit a report on the completed studies of possible natural resource damages.  PPL subsequently submitted the assessment report to the Pennsylvania and New Jersey regulatory agencies and has continued discussing potential natural resource damages and mitigation options with the agencies.  Subsequently, in August 2011 the PADEP submitted its National Resource Damage Assessment report to the court and to the interveners.  In December 2011, the interveners commented on the PADEP report and in February 2012 the PADEP and PPL filed separate responses with the court.  In March 2012, the court dismissed the interveners' case, but the interveners have appealed the dismissal to the Pennsylvania Supreme Court and a decision by the court is still pending.

Through December 31, 2012, PPL Energy Supply has spent $28 million for remediation and related costs and an insignificant remediation liability remains on the balance sheet.  PPL and PPL Energy Supply cannot be certain of the outcome of the natural resource damage assessment or the associated costs, the outcome of any lawsuit that may be brought by citizens or businesses or the nature of any other regulatory or legal actions that may be initiated against PPL, PPL Energy Supply or their subsidiaries as a result of the disposal basin release.  However, PPL and PPL Energy Supply currently do not expect such outcomes to result in significant losses above the amounts currently recorded.
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Seepages and Groundwater Infiltration - Pennsylvania, Montana and Kentucky

(PPL, PPL Energy Supply, LKE, LG&E and KU)

Seepages or groundwater infiltration have been detected at active and retired wastewater basins and landfills at various PPL, PPL Energy Supply, LKE, LG&E and KU plants.  PPL, PPL Energy Supply, LKE, LG&E and KU have completed or are completing assessments of seepages or groundwater infiltration at various facilities and have completed or are working with agencies to implement abatement measures, where required.  A range of reasonably possible losses cannot currently be estimated.

(PPL and PPL Energy Supply)

In 2007, six plaintiffs filed a lawsuit in the Montana Sixteenth Judicial District Court against the Colstrip plant owners asserting property damage due to seepage from plant wastewater ponds.  A settlement agreement was reached in July 2010 which would have resulted in a payment by PPL Montana, but certain of the plaintiffs later argued the settlement was not final.  The Colstrip plant owners filed a motion to enforce the settlement and in October 2011 the court granted the motion and ordered the settlement to be completed in 60 days.  The plaintiffs appealed the October 2011 order to the Montana Supreme Court, which affirmed the district court's order enforcing the settlement on December 31, 2012 and denied plaintiff's motion for rehearing on February 5, 2013.  The parties have 60 days after the February 5, 2013 decision to complete the settlement.  PPL Montana's share of the settlement is not expected to be significant.

In August 2012, PPL Montana entered into an Administrative Order on Consent (AOC) with the MDEQ which establishes a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at the Colstrip power plant.  The AOC requires that within five years, PPL Montana provide financial assurance to the MDEQ for the costs associated with closure and future monitoring of the waste-water treatment facilities.  PPL Montana cannot predict at this time if the actions required under the AOC will create the need to adjust the existing ARO related to these facilities.

In September 2012, Earthjustice filed an affidavit pursuant to Montana's Major Facility Siting Act (MFSA) that sought review of the AOC by Montana's Board of Environmental Review (BER), on behalf of the Sierra Club, the MEIC, and the National Wildlife Federation (NWF).  In September 2012, PPL Montana filed an election with the BER to have this proceeding conducted in Montana state district court as contemplated by the MFSA.  In October 2012, Earthjustice filed a petition for review of the AOC in the Montana state district court in Rosebud County.

In late October 2012, Earthjustice filed a second complaint against the MDEQ and PPL Montana in state district court in Lewis and Clark County on behalf of the Sierra Club, the MEIC and the NWF.  This complaint alleges that the defendants have failed to take action under the MFSA and the Montana Water Quality Act to effectively monitor and correct issues of coal ash disposal and wastewater ponds at the Colstrip plant.  The complaint seeks a declaration that the operations of the impoundments violate the statutes addressed above, requests a writ of mandamus directing the MDEQ to enforce the same, and seeks recovery of attorneys' fees and costs.  PPL is vigorously defending these allegations, and PPL and PPL Energy Supply cannot predict the outcome of this matter.

Clean Water Act 316(b)(PPL, PPL Energy Supply, LKE, LG&E and KU)

The EPA finalized requirements in 2004 for new or modified cooling water intake structures.  These requirements affect where generating plants are built, establish intake design standards and could lead to requirements for cooling towers at new and modified power plants.  In 2009, however, the U.S. Supreme Court ruled that the EPA has discretion to use cost-benefit analysis in determining the best technology available for minimizing adverse environmental impact to aquatic organisms.  The EPA published the proposed rule on new or modified cooling water intake structures in April 2011.  The industry and PPL reviewed the proposed rule and submitted comments.  The EPA has been evaluating comments and meeting with industry groups to discuss options.  Two NODAs have been issued on the rule that indicate the EPA may be willing to amend the rule based on certain industry group comments, and the EPA's comment period on the NODAs has ended.  The final rule is expected to be issued in 2013.  The proposed rule contains two requirements to reduce impact to aquatic organisms.  The first requires all existing facilities to meet standards for the reduction of mortality of aquatic organisms that become trapped against water intake screens regardless of the levels of mortality actually occurring or the cost of achieving the requirements.  The second requirement is to determine and install the best technology available to reduce mortality of aquatic organisms that are pulled through the plant's cooling water system.  A form of cost-benefit analysis is allowed for this second requirement.  This process involves a site-specific evaluation based on nine factors, including impacts to energy delivery reliability and the remaining useful life of the plant.  PPL, PPL Energy Supply, LKE, LG&E and KU cannot reasonably estimate a range of reasonably possible costs, if any, until a final rule is issued, the required studies have been completed, and each state in which they operate has decided how to implement the rule.
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Effluent Limitations Guidelines and Standards (PPL, PPL Energy Supply, LKE, LG&E and KU)

In October 2009, the EPA released its Final Detailed Study of the Steam Electric Power Generating effluent limitations guidelines and standards.  The EPA is expected to issue the final regulations in 2014.  PPL, PPL Energy Supply, LKE, LG&E and KU expect the revised guidelines and standards to be more stringent than the current standards especially for sulfur dioxide scrubber wastewater.  The guidelines are also expected to require dry ash handling, which could result in additional costs for technology retrofits for closure of wet basins.  In the interim, states may impose more stringent limits on a case-by-case basis under existing authority as permits are renewed.  Under the Clean Water Act, permits are subject to renewal every five years.  PPL, PPL Energy Supply, LKE, LG&E and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible costs, but the costs could be significant.

Other Issues (PPL, PPL Energy Supply, LKE, LG&E and KU)

In 2006, the EPA significantly decreased to 10 parts per billion (ppb) the drinking water standards for arsenic.  In Pennsylvania, Montana and Kentucky, this arsenic standard has been incorporated into the states' water quality standards and could result in more stringent limits in NPDES permits for PPL's Pennsylvania, Montana and Kentucky plants.  Subsequently, the EPA developed a draft risk assessment for arsenic that increases the cancer risk exposure by more than 20, which would lower the current standard from 10 ppb to  0.1 ppb.  If the lower standard becomes effective, costly treatment would be required to attempt to meet the standard and, at this time, there is no assurance that it could be achieved.  PPL, PPL Energy Supply, LKE, LG&E and KU cannot predict the outcome of the draft risk assessment and what impact, if any, it would have on their plants, but the costs could be significant.

The EPA is reassessing its polychlorinated biphenyls (PCB) regulations under the Toxics Substance Control Act, which currently allow certain PCB articles to remain in use.  In April 2010, the EPA issued an Advanced Notice of Proposed Rulemaking for changes to these regulations.  This rulemaking could lead to a phase-out of all PCB-containing equipment.  The EPA is planning to propose the revised regulations in late 2013.  PCBs are found, in varying degrees, in all of the Registrants' operations.  The Registrants cannot predict at this time the outcome of these proposed EPA regulations and what impact, if any, they would have on their facilities, but the costs could be significant.

A PPL Energy Supply subsidiary signed a Consent Order and Agreement (COA) with the PADEP in July 2008 under which it agreed, under certain conditions, to take further actions to minimize the possibility of fish kills at its Brunner Island plant.  Fish are attracted to warm water in the power plant discharge channel, especially during cold weather.  Debris at intake pumps can result in a unit trip or reduction in load, causing a sudden change in water temperature and fish mortality.  A barrier has been constructed to prevent debris from entering the river water intake area at a cost that was not significant.

PPL Energy Supply's subsidiary has also investigated alternatives to exclude fish from the discharge channel, but the subsidiary and the PADEP have concluded that a barrier method to exclude fish is not workable.  In June 2012, a new COA was signed that allows the subsidiary to study a change in a cooling tower operational method that may keep fish from entering the channel.  Should this approach fail, the new COA requires a retrofit of impingement control technology at the intakes to the cooling towers, the cost ofrestrictions, which could be significant.material.  Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.  

In May 2010, the subsidiary received a draft NPDES permit (renewed) for the Brunner Island plant from the PADEP.  This permit includes new water quality-based limits for the scrubber wastewater plant.  Some of these limits may not be achievable with the existing treatment system.  Several agencies and environmental groups commented on the draft permit, raising issues that must be resolved to obtain a final permit for the plant.  PPL Energy Supply cannot predict the outcome of the final resolution of the permit issues at this time, or what impact, if any, they would have on this facility, but the costs could be significant.

In May 2010, the Kentucky Waterways Alliance and other environmental groups filed a petition with the Kentucky Energy and Environment Cabinet challenging the Kentucky Pollutant Discharge Elimination System permit issued in April 2010, which covers water discharges from the Trimble County plant.  In November 2010, the Cabinet issued a final order upholding the permit.  In December 2010, the environmental groups appealed the order to the Trimble Circuit Court, but the case was subsequently transferred to the Franklin Circuit Court.  PPL, LKE, LG&E and KU are unable to predict the outcome of this matter or estimate a range of reasonably possible losses, if any.

The EPA and the Army Corps of Engineers are working on a guidance document that will expand the federal government's interpretation of what constitutes "waters of the United States" subject to regulation under the Clean Water Act.  This change has the potential to affect generation and delivery operations, with the most significant effect being the potential elimination of the existing regulatory exemption for plant waste water treatment systems.  The costs that may be imposed on the
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Registrants as a result of any eventual expansion of this interpretation cannot reliably be estimated at this time but could be significant.

Superfund and Other Remediation(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

PPL Electric is potentially responsible for costs at several sites listed by the EPA under the federal Superfund program, including the Columbia Gas Plant site, the Metal Bank site and the Ward Transformer site.  Clean-up actions have been or are being undertaken at all of these sites, the costs of which have not been significant to PPL Electric.  However, should the EPA require different or additional measures in the future, or should PPL Electric's share of costs at multi-party sites increase substantially more than currently expected, the costs could be significant.

PPL Electric, LG&E and KU are remediating or have completed the remediation of several sites that were not addressed under a regulatory program such as Superfund, but for which PPL Electric, LG&E and KU may be liable for remediation.  These include a number of former coal gas manufacturing plants in Pennsylvania and Kentucky previously owned or operated or currently owned by predecessors or affiliates of PPL Electric, LG&E and KU.  There are additional sites, formerly owned or operated by PPL Electric, LG&E and KU predecessors or affiliates, for which PPL Electric, LG&E and KU lack information on current site conditions and are therefore unable to predict what, if any, potential liability they may have.

Depending on the outcome of investigations at sites where investigations have not begun or been completed or developments at sites for which PPL Electric, LG&E and KU currently lack information, the costs of remediation and other liabilities could be material.  PPL, PPL Electric, LKE, LG&E and KU cannot estimate a range of reasonably possible losses, if any, related to these matters.

The EPA is evaluating the risks associated with polycyclic aromatic hydrocarbons and naphthalene, chemical by-products of coal gas manufacturing.  As a result of the EPA's evaluation, individual states may establish stricter standards for water quality and soil cleanup.  This could require several PPL subsidiaries to take more extensive assessment and remedial actions at former coal gas manufacturing plants.  PPL, PPL Electric, LKE, LG&E and KU cannot estimate a range of reasonably possible losses, if any, related to these matters.

Under the Pennsylvania Clean Streams Law, subsidiariesa subsidiary of PPLTalen Generation areis obligated to remediate acid mine drainage at a former mine sitessite and may be required to take additional steps to prevent potential acid mine drainage at the previously capped refuse piles.  One PPL Generationpile at this mine site. The subsidiary is currently pumping and treating mine water at twothe former mine sites and treating water at one of these sites.  Another PPL Generation subsidiary has installed a passive wetlands treatment system at a third site.

At December 31, 2012, PPL Energy Supply2015, Talen Generation had accrued a discounted liability of $26$19 million to cover the costs of pumping and treating groundwater at the tworemaining mine sitessite for 50 years and for operating and maintaining passive wetlands treatment at the third site.  PPLyears. Talen Energy Supply discounted this liability based on a risk-free ratesrate of 8.41% at the time of the mine closures.  The weighted-average rate used was 8.19%.closure. Expected undiscounted payments are estimated at $3 million for 2013, $1 millionto be insignificant for each of the years from 20142016 through 2017,2020 and $139$92 million for work after 2017.2020.

From time to time, PPLtime-to-time, Talen Energy Supply, PPL Electric, LG&E and KU undertakeundertakes investigative or remedial actionactions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiatenegotiates with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiatenegotiates with property owners and other third parties alleging impacts from PPL'sTalen Energy's operations and undertakeundertakes similar actions necessary to resolve environmental matters which arise in the course of normal operations.  Based on analyses to date,analysis to-date, resolution of these known environmental matters is not expected to have a significantmaterial adverse impacteffect on theirTalen Energy's financial condition or results of operations.

Future cleanupinvestigation or remediation work at sites currently under review, or at sites not currently identified, may result in significant additional costs for the Registrants.Talen Energy, but at this time Talen Energy is unable to determine if such investigation or remediation work will have a material adverse effect on Talen Energy's financial condition or results of operations.


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Other

Environmental Matters - WPD (PPL)In addition to the environmental matters discussed above, from time-to-time in the ordinary course of its business Talen Energy may become involved in other environmental matters or become subject to other environmental statutes, regulations or requirements. In the opinion of management, based upon information currently available to Talen Energy, while the outcome of these other environmental matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.

Other Commitments and Contingencies

WPD's distribution businesses are subject to environmental regulatory and statutory requirements.  PPL believes that WPD has taken and continues to take measures to comply with the applicable laws and governmental regulations for the protection of the environment.Nuclear Insurance

The U.K. Government has requested that utilities undertake projectsPrice-Anderson Act is a United States Federal law which governs liability-related issues and ensures the availability of funds for public liability claims arising from an incident at any U.S. licensed nuclear facility.  It also seeks to alleviatelimit the impactliability of flooding onnuclear reactor owners for such claims from any single incident.  At December 31, 2015, the U.K. utility infrastructure, including major electricity substations.  WPD has agreed withliability limit per incident is $13.3 billion for such claims which is funded by insurance coverage from American Nuclear Insurers and an industry assessment program.

Under the Ofgem to spend $45 million on flood prevention, which will be recovered through rates duringindustry retroactive assessment program, in the ten-year period commencing April 2010.  WPD is currently liaising on site-specific proposals with local officesevent of a U.K. Government agency.
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There are no other material legal or administrative proceedings pending against or relatednuclear incident at any of the reactors covered by The Price-Anderson Act, as amended, Susquehanna Nuclear could be assessed deferred premiums of up to WPD with respect to environmental matters.$255 million per incident, payable at a maximum of $38 million per year.

Other

Additionally, Susquehanna Nuclear Insurance(PPL and PPL Energy Supply)

PPLpurchases property insurance programs from NEIL, an industry mutual insurance company of which Susquehanna Nuclear is a member of certain insurance programs that provide coverage for property damage to members' nuclear generating plants.  Facilitiesmember.  Effective April 1, 2015, facilities at the Susquehanna plant are insured against property damage losses up to $2.75 billion under these programs.  PPL$2.0 billion.  Susquehanna isNuclear also a member ofpurchases an insurance program that provides insurance coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.

Under the NEIL property and replacement power insurance programs, PPL Susquehanna Nuclear could be assessed retroactiveretrospective premiums in the event of the insurers' adverse loss experience.  At December 31, 2012, thisThis maximum assessment was $48is $55 million. Talen Energy has additional coverage that, under certain conditions, may reduce this exposure.

Labor Union Agreements

In May 2014, Talen Energy's bargaining agreement with its largest IBEW local expired. Talen Energy finalized a new three-year labor agreement with IBEW local 1600 in May 2014 and the eventagreement was ratified in early June 2014.

As part of efforts to reduce operations and maintenance expenses, the new agreement offered a nuclear incident atone-time voluntary retirement window to certain bargaining unit employees. The benefits offered under this provision are consistent with the Susquehanna plant, PPL Susquehanna's publicstandard separation program benefits for bargaining unit employees. In 2014, the following charges for separation benefits were recorded.
Pension Benefits $11
Severance Compensation 6
Total Separation Benefits $17
Number of Employees 105

The separation benefits are included in "Operation and maintenance" on the Statement of Income. The liability for claims resulting from such incident would be limited to $12.6 billion under provisionspension benefits is included in "Accrued pension obligations" on the Balance Sheets. All of The Price-Anderson Act as amended.  PPL Susquehanna is protected against this liability by a combination of commercial insurance and an industry assessment program.the severance compensation was paid in 2014.

In the event of a nuclear incident at any of the reactors covered by The Price-Anderson Act as amended, PPL Susquehanna could be assessed up to $235 million per incident, payable at $35 million per year.

Guarantees and Other Assurances

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

In the normal course of business, the Registrants enterTalen Energy enters into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries.  Such agreements include, for example, guarantees, stand-by letters of credit issued by financial institutions and surety bonds issued by insurance companies.  These agreements are entered into primarily to support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries engage.

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(PPL)

PPL fully and unconditionally guarantees allTable of the debt securities of PPL Capital Funding.Contents

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The table below details guarantees provided as of December 31, 2012.2015.  "Exposure" represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee.  The totalprobability of expected payment/performance for the guarantees described below is remote. There was no recorded liability at December 31, 2012 and 20112015. The recorded liability at December 31, 2014 was $24 million and $14 million for PPL and $20 million and $11 million for LKE.  The probability of expected payment/performance under each of these guarantees is remote except for "WPD guarantee of pension and other obligations of unconsolidated entities" and "Indemnification of lease termination and other divestitures."  For reporting purposes, on a consolidated basis, all guarantees of PPL Energy Supply (other than the letters of credit), PPL Electric, LKE, LG&E and KU also apply to PPL, and all guarantees of LG&E and KU also apply to LKE.$13 million.

   Exposure at Expiration
   December 31, 2012 (a) Date
PPL      
Indemnifications related to the WPD Midlands acquisition   (b)  
WPD indemnifications for entities in liquidation and sales of assets $ 11 (c) 2015
WPD guarantee of pension and other obligations of unconsolidated entities   91 (d) 2015
        
PPL Energy Supply      
Letters of credit issued on behalf of affiliates   23 (e) 2013 - 2014
Retrospective premiums under nuclear insurance programs   48 (f)  
Nuclear claims assessment under The Price-Anderson Act Amendments      
 under The Energy Policy Act of 2005   235 (g)  
Indemnifications for sales of assets   250 (h) 2025
Indemnification to operators of jointly owned facilities   6 (i)  
Guarantee of a portion of a divested unconsolidated entity's debt   22 (j) 2018
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   Exposure at Expiration
   December 31, 2012 (a) Date
PPL Electric      
Guarantee of inventory value   21 (k) 2016
        
LKE      
Indemnification of lease termination and other divestitures   301 (l) 2021 - 2023
        
LG&E and KU      
LG&E and KU guarantee of shortfall related to OVEC   (m)  

(a)Represents the estimated maximum potential amount of future payments that could be required to be made under the guarantee.
(b)Prior to PPL's acquisition, WPD Midlands Holdings Limited had agreed to indemnify certain former directors of a Turkish entity in which WPD Midlands Holdings Limited previously owned an interest, for any liabilities that may arise as a result of an investigation by Turkish tax authorities, and PPL WEM has received a cross-indemnity from E.ON AG with respect to these indemnification obligations.  Additionally, PPL subsidiaries agreed to provide indemnifications to subsidiaries of E.ON AG for certain liabilities relating to properties and assets owned by affiliates of E.ON AG that were transferred to WPD Midlands in connection with the acquisition.  The maximum exposure and expiration of these indemnifications cannot be estimated because the maximum potential liability is not capped and the expiration date is not specified in the transaction documents.
(c)In connection with the liquidation of wholly owned subsidiaries that have been deconsolidated upon turning the entities over to the liquidators, certain affiliates of PPL Global have agreed to indemnify the liquidators, directors and/or the entities themselves for any liabilities or expenses arising during the liquidation process, including liabilities and expenses of the entities placed into liquidation.  In some cases, the indemnifications are limited to a maximum amount that is based on distributions made from the subsidiary to its parent either prior or subsequent to being placed into liquidation.  In other cases, the maximum amount of the indemnifications is not explicitly stated in the agreements.  The indemnifications generally expire two to seven years subsequent to the date of dissolution of the entities.  The exposure noted only includes those cases in which the agreements provide for a specific limit on the amount of the indemnification, and the expiration date was based on an estimate of the dissolution date of the entities.

In connection with their sales of various businesses, WPD and its affiliates have provided the purchasers with indemnifications that are standard for such transactions, including indemnifications for certain pre-existing liabilities and environmental and tax matters.  In addition, in connection with certain of these sales, WPD and its affiliates have agreed to continue their obligations under existing third-party guarantees, either for a set period of time following the transactions or upon the condition that the purchasers make reasonable efforts to terminate the guarantees.  Finally, WPD and its affiliates remain secondarily responsible for lease payments under certain leases that they have assigned to third parties.
(d)As a result of the privatization of the utility industry in the U.K., certain electric associations' roles and responsibilities were discontinued or modified.  As a result, certain obligations, primarily pension-related, associated with these organizations have been guaranteed by the participating members.  Costs are allocated to the members based on predetermined percentages as outlined in specific agreements.  However, if a member becomes insolvent, costs can be reallocated to and are guaranteed by the remaining members.  At December 31, 2012, WPD has recorded an estimated discounted liability based on its current allocated percentage of the total expected costs for which the expected payment/performance is probable.  Neither the expiration date nor the maximum amount of potential payments for certain obligations is explicitly stated in the related agreements.  Therefore, they have been estimated based on the types of obligations.
(e)Standby letter of credit arrangements under PPL Energy Supply's credit facilities for the purposes of protecting various third parties against nonperformance by PPL.  This is not a guarantee by PPL on a consolidated basis.
(f)PPL Susquehanna is contingently obligated to pay this amount related to potential retrospective premiums that could be assessed under its nuclear insurance programs.  See "Nuclear Insurance" above for additional information.
(g)This is the maximum amount PPL Susquehanna could be assessed for each incident at any of the nuclear reactors covered by this Act.  See "Nuclear Insurance" above for additional information.
(h)PPL Energy Supply's maximum exposure with respect to certain indemnifications and the expiration of the indemnifications cannot be estimated because, in the case of certain indemnification provisions, the maximum potential liability is not capped by the transaction documents and the expiration date is based on the applicable statute of limitation.  The exposure and expiration dates noted are only for those cases in which the agreements provide for specific limits.  The indemnification provisions described below are in each case subject to certain customary limitations, including thresholds for allowable claims, caps on aggregate liability, and time limitations for claims arising out of breaches of most representations and warranties.

A subsidiary of PPLTalen Energy Supply has agreedindemnifications related to provide indemnification tosales of assets that are governed by the purchaser of the Long Island generation business for damages arising out of anyspecific sales agreement and include breach of the representations, warranties and covenants, underand liabilities for certain other matters.  Talen Energy's maximum exposure with respect to certain indemnifications and the expiration of the indemnifications cannot be estimated because the maximum potential liability is not capped by the transaction documents and the expiration date is based on the applicable statute of limitations.  The exposure and expiration date noted is based on those cases in which the agreements provide for specific limits. The exposure at December 31, 2015 includes amounts related transaction agreementto the sale of the Talen Montana hydroelectric facilities. See Note 6 for additional information related to the sale. Talen Energy's exposure and related expiration dates are:
 December 31, 2015 Expiration Date
Indemnifications for sales of assets$1,150
 2016 - 2025
In connection with the acquisition of RJS Power and the spinoff from PPL, Talen Energy Supply agreed to indemnify PPL and its affiliates following the spinoff for damagesliabilities primarily relating to the Talen Energy Supply business prior to the spinoff, as well as for losses arising out of breaches of Talen Energy's failure to perform covenants and agreements in the transaction agreements following the spinoff or arising out of breaches by the Riverstone Holders of certain other matters, includingrepresentations and warranties in the transaction agreements.  Talen Energy Supply also agreed to indemnify PPL for liabilities relating to certain renewable energy facilities whichthe employment or termination of service of PPL employees who primarily supported the Talen Energy Supply business prior to the spinoff (excluding however defined benefit pension obligations of PPL employees who terminated service prior to July 1, 2000 or who were previously ownednot employed by oneTalen Energy Supply or its subsidiaries at the time of termination).  Talen Energy Supply also agreed to indemnify PPL from tax liabilities resulting from actions by Talen Energy following the PPL subsidiaries soldclosing resulting in the transaction but which were unrelatedfailing to the Long Island generation business.  The indemnification provisionsqualify for most representations and warranties expired in the third quarter of 2011.its intended tax-free treatment.

A subsidiary of PPLTalen Energy Supply has agreed to provide indemnification to the purchasers of the Maine hydroelectric facilities for damages arising out of any breach of the representations, warranties and covenants under the respective transaction agreements and for damages arising out of certain other matters, including liabilities of the PPL Energy Supply subsidiary relating to the pre-closing ownership and/or operation of those hydroelectric facilities.  The indemnification provisions for most representations and warranties expired in the fourth quarter of 2012.

Subsidiaries of PPL Energy Supply have agreed to provide indemnification to the purchasers of certain non-core generation facilities sold in March 2011 for damages arising out of any breach of the representations, warranties and covenants under the related transaction agreements and for damages arising out of certain other matters relating to the facilities that were the subject of the transaction, including certain reduced capacity payments (if any) at one of the facilities in the event specified PJM rule changes are proposed and become effective.  The indemnification provisions for most representations and warranties expired in the first quarter of 2012.
(i)In December 2007, a subsidiary of PPL Energy Supply executed revised owners agreements for two jointly owned facilities, the Keystone and Conemaugh generating plants.  The agreements require that in the event of any default by an owner, the other owners fund contributions for the operation of the generating plants, based upon their ownership percentages.  The non-defaulting owners, who make up the defaulting owner's obligations, are entitled to the generation entitlement of the defaulting owner, based upon their ownership percentage.  The exposure shown reflects the PPL Energy Supply subsidiary's share of the maximum obligation.  The agreements do not have an expiration date.
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(j)A PPL Energy Supply subsidiary owned a one-third equity interest in Safe Harbor Water Power Corporation (Safe Harbor) that was sold in March 2011.  Beginning in 2008, PPL Energy Supply guaranteed one-third of any amounts payable with respect to certain senior notes issued by Safe Harbor.  Under the terms of the sale agreement, PPL Energy Supply continues to guarantee the portion of Safe Harbor's debt, but received a cross-indemnity from the purchaser, secured by a lien on the purchaser's stock of Safe Harbor, in the event PPL Energy Supply is required to make a payment under the guarantee.  The exposure noted reflects principal only.  See Note 9 for additional information on the sale of this interest.
(k)PPL Electric entered into a contract with a third party logistics firm that provides inventory procurement and fulfillment services.  Under the contract, the logistics firm has title to the inventory purchased for PPL Electric's use.  Upon termination of the contract, PPL Electric has guaranteed to purchase any remaining inventory that has not been used or sold by the logistics firm at the weighted-average cost at which the logistics firm purchased the inventory, thus protecting the logistics firm from reductions in the fair value of the inventory.
(l)LKE provides certain indemnifications, the most significant of which relate to the termination of the WKE lease in July 2009.  See Note 9 for additional information.  These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations.  The most comprehensive of these guarantees is the LKE guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement.  This guarantee has a term of 12 years ending July 2021, and a cumulative maximum exposure of $200 million.  Certain items such as government fines and penalties fall outside the cumulative cap.  LKE has contested the applicability of the indemnification requirement relating to one matter presented by a counterparty under this guarantee.  Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023.  In May 2012, LKE's indemnitee received an arbitration panel's decision affecting this matter, which granted LKE's indemnitee certain rights of first refusal to purchase excess power at a market-based price rather than at an absolute fixed price.  In January 2013, LKE's indemnitee commenced a proceeding in the Kentucky Court of Appeals appealing a December 2012 order of the Henderson Circuit Court confirming the arbitration award.  LKE believes its indemnification obligations in this matter remain subject to various uncertainties, including the potential for additional legal challenges regarding the arbitration decision as well as future prices, availability and demand for the subject excess power.  LKE continues to evaluate various legal and commercial options with respect to this indemnification matter.  The ultimate outcomes of the WKE termination-related indemnifications cannot be predicted at this time.  Additionally, LKE has indemnified various third parties related to historical obligations for other divested subsidiaries and affiliates.  The indemnifications vary by entity and the maximum exposures range from being capped at the sale price to no specified maximum; however, LKE is not aware of formal claims under such indemnities made by any party at this time.  LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party.  In the second quarter of 2012, LKE adjusted its estimated liability for certain of these indemnifications by $9 million ($5 million after-tax), which is reflected in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income.  The adjustment was recorded in the Kentucky Regulated segment for PPL.  LKE cannot predict the ultimate outcomes of such indemnification circumstances, but does not currently expect such outcomes to result in significant losses above the amounts recorded.
(m)As described in the "Energy Purchase Commitments" above, pursuant to the OVEC power purchase contract, expiring in June 2040, LG&E and KU are obligated to pay a demand charge which includes, among other charges, debt service and amortization toward principal retirement, decommissioning costs, post-retirement and post-employment benefits costs (other than pensions), and reimbursement of plant operating, maintenance and other expenses.  The demand charge is expected to cover LG&E's and KU's shares of the cost of the listed items over the term of the contract.  However, in the event there is a shortfall in covering these costs, LG&E and KU are obligated to pay their share of the excess debt service, post-retirement and decommissioning costs.  The maximum exposure and the expiration date of these potential obligations are not presently determinable.

The Registrants provide other miscellaneous guarantees through contracts entered into in the normal course of business.  These guarantees are primarily in the form of indemnification or warranties related to services or equipment and vary in duration.  The amounts of these guarantees often are not explicitly stated, and the overall maximum amount of the obligation under such guarantees cannot be reasonably estimated.  Historically, no significant payments have been made with respect to these types of guarantees and the probability of payment/performance under these guarantees is remote.

PPL,Talen Energy, on behalf of itself and certain of its subsidiaries, maintains insurance that covers liability assumed under contract for bodily injury and property damage.  The coverage requires a maximum $4 million deductible per occurrence and provides maximum aggregate coverage of $200$100 million.  This insurance may be applicable to obligations under certain of these contractual arrangements.

16.
12.  Related Party Transactions

(Prior to the spinoff, PPL Energy SupplyElectric and PPL Electric)Services were affiliates of Talen Energy. The disclosures below provide information regarding transactions that occurred prior to June 1, 2015. After June 1, 2015, transactions with PPL Electric and PPL Services, or any other PPL subsidiaries are not related party transactions.

PLR Contracts/PurchaseSales of Accounts Receivable

PPL Electric holds competitive solicitations for PLR generatinggeneration supply.  PPL EnergyPlusTalen Energy Marketing has been awarded a portion of the PLR generation supply through these competitive solicitations.  See Note 15 for additional information on the solicitations.  The sales and purchases between PPL EnergyPlusTalen Energy Marketing and PPL Electric for the five months ended May 31, 2015 and the years ended December 31, 2014 and 2013 are included in the Statements of Income as "Wholesale energy marketing to affiliate" by PPL Energy Supply and as "Energy purchases from affiliate" by PPL Electric.

Under the standard Supply Master Agreement for the solicitation process, PPL Electric requires all suppliers to post collateral once credit exposures exceed defined credit limits.  PPL EnergyPlus is required to post collateral with PPL Electric:  (a) when the market price of electricity to be delivered by PPL EnergyPlus exceeds the contract price for the forecasted quantity of electricity to be delivered and (b) this market price exposure exceeds a contractual credit limit.  Based on the current credit rating of PPL Energy Supply, as guarantor, PPL EnergyPlus' credit limit was $35 million at December 31, 2012.  In no instance is PPL Electric required to post collateral to suppliers under these supply contracts.Talen Energy.

PPL Electric's customers may choose an alternative supplier for their generation supply.  See Note 1 for additional information regardingAs part of a PUC-approved purchase of accounts receivable program, PPL Electric'sElectric purchases ofcertain accounts receivable from alternative electricity suppliers including PPL EnergyPlus.
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At(including Talen Energy Marketing) at a discount. During the five month period up to the spinoff included in the year ended December 31, 2012, PPL2015, Talen Energy Supply had a net credit exposure of $27 million to PPL Electric from its commitment as a PLR supplier and from the sale of itsMarketing sold accounts receivable to PPL Electric.Electric of $146 million, $336 million for the year ended December 31, 2014 and $294 million for the year ended December 31, 2013. Losses resulting from the sales of accounts receivable to PPL Electric during these periods were not material.      


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Support Costs

Wholesale Sales and Purchases (LG&E and KU)

LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.  When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E.  When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU.  These transactions are reflected in the Statements of Income as "Electric revenue from affiliate" and "Energy purchases from affiliate" and are recorded at a price equalPrior to the seller's fuel cost.  Savings realizedspinoff, Talen Energy was provided with administrative, management and support services, primarily from such intercompany transactions are shared equally between both companies.  The volumePPL Services. Where applicable, the costs of energy each company hasthese services were charged to sellTalen Energy Supply as direct support costs.  General costs that could not be directly attributed to a specific affiliate were allocated and charged to the other is dependent on its native load needs and its available generation.

Allocations ofrespective affiliates, including Talen Energy Supply, as indirect support costs.  PPL Services Costs(PPL Energy Supply, PPL Electric and LKE)

PPL Services provides corporate functions such as financial, legal, human resources and information technology services.  PPL Services chargesused a three-factor methodology that includes the respective PPL subsidiaries for the cost of such services when they can be specifically identified.  The cost of the services that is not directly charged to PPL subsidiaries is allocated to applicable subsidiaries based on an average of the subsidiaries' relativeaffiliates invested capital, operation and maintenance expenses and number of employees.employees to allocate indirect costs, which methodology Talen Energy believes was reasonable. 

Talen Energy Supply was charged, primarily by PPL Services, charged the following amounts for the years ended December 31, which PPL management believes are reasonable, including amounts applied to accounts that are further distributed between capital and expense.
  2015 2014 2013
  $67
 $218
 218

   2012   2011   2010  
           
PPL Energy Supply $ 212  $ 189  $ 232  
PPL Electric   157    145    134  
LKE   15    16    3 (a)
Transition Services Agreement

(a)
Represents costs allocated during the two months ended December 31, 2010 as LKE was acquired November 1, 2010.     

Intercompany Billings by LKS (LG&E and KU)

LKS provides LG&E and KU with a varietyAs part of centralized administrative, management and support services.  The cost of these services is directly charged to the company or, for general costs that cannot be directly attributed, charged based on predetermined allocation factors, including the following measures: number of customers, total assets, revenues, number of employees and/or other statistical information.  LKS charged the amounts in the table below, which LKE management believes are reasonable, including amounts that are further distributed between capital and expense.

  Successor  Predecessor
        Two Months  Ten Months
  Year Ended  Year Ended  Ended  Ended
  December 31,  December 31,  December 31,  October 31,
  2012   2011   2010   2010 
                
LG&E $186   $190   $32   $200 
KU  161    204    34    222 

In addition, LG&E and KU provide services to each other and to LKS.  Billings between LG&E and KU relate to labor and overheads associated with union and hourly employees performing work for the other company, charges related to jointly-owned generating units and other miscellaneous charges.  Tax settlements between LKE and LG&E and KU are reimbursed through LKS.

Intercompany Borrowings

(PPL Energy Supply)

A PPLspinoff transaction, Talen Energy Supply subsidiary periodically holds revolving linesentered into a TSA with Topaz Power Management, LP (an affiliate of credit and demand notes fromRiverstone) for certain affiliates that are reflected in "Note receivable from affiliates" onbusiness administrative services. For the Balance Sheet.  Atyear ended December 31, 2012, there were no outstanding balances.  At December 31, 2011, a note with PPL Energy Funding had an outstanding balance of $198 million with an interest rate of 3.77%.  Interest earned on2015, these revolving facilities is includedcosts which are recorded in "Interest Income from Affiliates" on the Statements of Income.  For 2012, interest earned on borrowings was insignificant.  For 2011, interest earned on borrowings,
359
which was substantially attributable to borrowings by PPL Energy Funding as discussed above, was $8 million.  For 2010, interest earned on borrowings, excluding the term notes discussed below, was $5 million with interest rates equal to one-month LIBOR plus a spread.

(PPL Energy Supply, LKE, LG&E and KU)

In November 2010, a PPL Energy Supply subsidiary held term notes with LG&E and KU.  These notes were subsequently repaid and therefore no balances were outstanding at December 31, 2010.  Interest on these notes was included in "Interest Income from Affiliates" for PPL Energy Supply and "Interest Expense with Affiliate" for LKE, LG&E and KU.  When balances were outstanding, interest on these notes was insignificant for 2010.

(LKE)

LKE maintains a $300 million revolving line of credit with a PPL Energy Funding subsidiary whereby LKE can borrow funds on a short-term basis at market-based rates.  The interest rates on borrowings are equal to one-month LIBOR plus a spread.  At December 31, 2012, $25 million was outstanding and was reflected in "Notes payable with affiliates" on the Balance Sheet.  The interest rate on the outstanding borrowing at December 31, 2012 was 1.71%.  The line of credit was held by another PPL subsidiary in 2011.  No balance was outstanding at December 31, 2011.  Interest on the revolving line of credit was not significant for 2012 or 2011.

LKE maintains an agreement with a PPL affiliate that has a $300 million borrowing limit whereby LKE can loan funds on a short-term basis at market-based rates.  At December 31, 2012, there was no outstanding balance.  At December 31, 2011, $15 million was outstanding and was reflected in "Notes receivable from affiliates" on the Balance Sheet.  The interest rates on loans are based on the PPL affiliate's credit rating and are currently equal to one-month LIBOR plus a spread.  The interest rate on the outstanding borrowing at December 31, 2011 was 2.27%.  Interest income on this note was not significant in 2012 or 2011.

(LG&E)

LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to $500 million at an interest rate based on a market index of commercial paper issues.  At December 31, 2012 and 2011, there was no balance outstanding.  Interest expense incurred and interest income earned on the money pool agreement with LKE and/or KU was not significant for 2012, 2011 or 2010.

(KU)

KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to $500 million at an interest rate based on a market index of commercial paper issues.  At December 31, 2012 and 2011, there was no balance outstanding.  Interest expense incurred and interest income earned on the money pool agreement with LKE and/or LG&E was not significant for 2012, 2011 or 2010.

Intercompany Derivatives (LKE, LG&E and KU)

In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL for notional amounts of $150 million each.  These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties.  See Note 19 for additional information on intercompany derivatives.

(PPL Energy Supply)

Trademark Royalties

A PPL subsidiary owns PPL trademarks and billed certain affiliates for their use under a licensing agreement.  This agreement was terminated in December 2011.  PPL Energy Supply was charged $40 million of license fees in 2011 and 2010.  These charges are primarily included in "Other operation"Operation and maintenance" on the StatementsStatement of Income, were $6 million.

Gas Supply Contract

A subsidiary of Jade has a gas supply contract in place with TrailStone NA Logistics LLC (TrailStone), an affiliate of Riverstone, under which TrailStone supplies gas to the generation facilities owned by Jade. For the year ended December 31, 2015, Talen Energy incurred $52 million of costs for these gas purchases, which are primarily recorded in "Fuel" on the Statement of Income.
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Distribution of Interest in PPL Global to Parent

In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent, PPL Energy Funding.  See Note 9 for additional information.

Intercompany Insurance (PPL Electric)

PPL Power Insurance Ltd. (PPL Power Insurance) is a subsidiary of PPL that provides insurance coverage to PPL and its subsidiaries for property damage, general/public liability and workers' compensation.

Due to damages resulting from several PUC-reportable storms that occurred in 2012 and 2011, PPL Electric exceeded its deductible for both policy years.  Probable recoveries on insurance claims with PPL Power Insurance of $18.25 million for 2012 and $26.5 million for 2011 were recorded in those years, of which $14 million and $16 million were included in "Other operation and maintenance" on the Statements of Income.  In both years, the remainder was recorded in PP&E on the Balance Sheets.  In September 2012, PPL Electric received $26.5 million from the settlement of its 2011 claims.

Effective January 1, 2013, PPL Electric no longer has storm insurance with PPL Power Insurance.

Other(PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

See Note 1, for discussions regarding the intercompany tax sharing agreementallocations associated with income taxes and stock-based compensation, and Note 79 for a discussion regarding capital transactions by PPL Energy Supply, PPL Electric, LKE, LG&E and KU.  For PPL Energy Supply, PPL Electric and LKE, refer to Note 1 for discussions regarding intercompany allocations of stock-based compensation expense.  For PPL Energy Supply, PPL Electric, LG&E and KU, see Note 13 for discussions regarding intercompany allocations associated with defined benefits.

13.  Other Income (Expense) - net

17.  Other Income (Expense) - net
            
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
            
The breakdown of "Other Income (Expense) - net" for the years ended December 31 was:
            
    PPL
    2012  2011  2010 
Other Income         
 Earnings on securities in NDT funds $ 22  $ 24  $ 20 
 Interest income   5    7    8 
 AFUDC - equity component   10    7    5 
 Net hedge gains associated with the 2011 Bridge Facility (a)      55    
 Earnings (losses) from equity method investments   (8)   1    2 
 Gain on redemption of debt (b)      22    
 Miscellaneous - Domestic   11    10    3 
 Miscellaneous - U.K.   2   1    1 
 Total Other Income   42    127    39 
Other Expense         
 Economic foreign currency exchange contracts (Note 19)   52    (10)   (3)
 Charitable contributions   10    9    4 
 Cash flow hedges (c)         29 
 LKE acquisition-related costs (Note 10)         31 
 WPD Midlands acquisition-related costs (Note 10)      34    
 Foreign currency loss on 2011 Bridge Facility (d)      57    
 U.K. stamp duty tax (Note 10)      21    
 Miscellaneous - Domestic   16    9    7 
 Miscellaneous - U.K.   3    3    2 
 Total Other Expense   81    123    70 
Other Income (Expense) - net $ (39) $ 4  $ (31)
361
    Successor  Predecessor
        Two Months  Ten Months
    Year Ended Year Ended Ended  Ended
    December 31, December 31, December 31,  October 31,
    2012  2011  2010   2010 
LKE             
Other Income             
 Net derivative gains (losses)           $ 19 
 Interest income    $ 1        
 Earnings (losses) from equity method investments $ (8)   1        3 
 Life insurance   1           2 
 Miscellaneous   3    2        1 
 Total Other Income   (4)   4        25 
Other Expense             
 Charitable contributions   4    4  $ 1     5 
 Joint-use-asset depreciation             3 
 Miscellaneous   7    1    1     3 
 Total Other Expense   11    5    2     11 
Other Income (Expense) - net $ (15) $ (1) $ (2)  $ 14 
                
LG&E             
Other Income             
 Net derivative gains (losses)           $ 19 
 Miscellaneous $ 1           1 
 Total Other Income   1           20 
Other Expense             
 Charitable contributions   2  $ 1        2 
 Miscellaneous   2    1  $ 3     1 
 Total Other Expense   4    2    3     3 
Other Income (Expense) - net $ (3) $ (2) $ (3)  $ 17 
                
KU             
Other Income             
 Earnings (losses) from equity method investments $ (8) $ 1      $ 3 
 Life insurance   1           2 
 Miscellaneous   1           1 
 Total Other Income   (6)   1        6 
Other Expense             
 Charitable contributions   1    1        1 
 Joint-use-asset depreciation             3 
 Miscellaneous   1    1        1 
 Total Other Expense   2    2        5 
Other Income (Expense) - net $ (8) $ (1)     $ 1 
(a)Represents a gain on foreign currency contracts that hedged the repayment of the 2011 Bridge Facility borrowing.
(b)In July 2011, as a result of PPL Electric's redemption of 7.125% Senior Secured Bonds due 2013, PPL recorded a gain on the accelerated amortization of the fair value adjustment to the debt recorded in connection with previously settled fair value hedges.
(c)Represents losses reclassified from AOCI into earnings associated with discontinued hedges at PPL for debt that had been planned to be issued by PPL Energy Supply.  As a result of the expected net proceeds from the sale of certain non-core generation facilities, coupled with the monetization of full-requirement sales contracts, the debt issuance was no longer needed.
(d)Represents a foreign currency loss related to the repayment of the 2011 Bridge Facility borrowing.

"OtherTalen Energy's "Other Income (Expense) - net" for the year ended December 31, 2015 was primarily related to a charge for a termination payment to a remarketing dealer in conjunction with an October 2015 redemption of debt. See Note 5 for additional information on the redemption. For the years ended December 31, 2012, 20112014 and 2010 is2013, the activity was primarily related to the earnings on securities in NDT funds for PPL Energy Supply and the equity component of AFUDC for PPL Electric.funds. 

18.
14.  Fair Value Measurements and Credit Concentration

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price).  A market approach (generally, data from market transactions), an income approach (generally, present value techniques and option-pricing models), and/or a cost approach (generally, replacement cost) are used to measure the fair value of an asset or liability, as appropriate.  These valuation approaches incorporate inputs such as observable, independent market data and/or unobservable data that management believes are predicated on the assumptions market participants would use to price an asset or liability.  These inputs may incorporate, as applicable, certain risks such as nonperformance risk, which includes credit risk.  The fair value of a group of financial assets and liabilities is measured on a net basis.  Transfers between levels are recognized at end-of-reporting-period values.  During 2012,2015 and 2014, there were no transfers between Level 1 and Level 2.  See Note 1 for information on the levels in the fair value hierarchy.


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Table of Contents

Recurring Fair Value Measurements

The assets and liabilities measured at fair value were:

 December 31, 2015 December 31, 2014
 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
Assets               
Cash and cash equivalents$141
 $141
 $—
 $—
 $352
 $352
 $—
 $—
Restricted cash and cash equivalents (a)106
 106
 —
 —
 193
 193
 —
 —
Price risk management assets:               
Energy commodities693
 —
 597
 96
 1,318
 6
 1,171
 141
Total price risk management assets693
 —
 597
 96
 1,318
 6
 1,171
 141
NDT funds:               
Cash and cash equivalents11
 11
 —
 —
 19
 19
 —
 —
Equity securities           
  
  
U.S. large-cap616
 457
 159
 —
 611
 454
 157
 —
U.S. mid/small-cap87
 37
 50
 —
 89
 37
 52
 —
Debt securities           
  
  
U.S. Treasury98
 98
 —
 —
 99
 99
 —
 —
U.S. government sponsored agency6
 —
 6
 —
 9
 —
 9
 —
Municipality83
 —
 83
 —
 76
 —
 76
 —
Investment-grade corporate47
 —
 47
 —
 42
 —
 42
 —
Other3
 —
 3
 —
 3
 —
 3
 —
Receivables (payables), net—
 (2) 2
 —
 2
 —
 2
 —
Total NDT funds951
 601
 350
 —
 950
 609
 341
 —
Auction rate securities (b)6
 —
 —
 6
 8
 —
 —
 8
Total assets$1,897
 $848
 $947
 $102
 $2,821
 $1,160

$1,512

$149
Liabilities               
Price risk management liabilities:               
Energy commodities$539
 $—
 $497
 $42
 $1,217
 $5
 $1,182
 $30
Total price risk management liabilities$539
 $—
 $497
 $42
 $1,217
 $5

$1,182

$30
     December 31, 2012 December 31, 2011
     Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
PPL                        
Assets                        
 Cash and cash equivalents $ 901  $ 901        $ 1,202  $ 1,202       
 Restricted cash and cash equivalents (a)   135    135          209    209       
 Price risk management assets:                        
  Energy commodities   2,068    2  $ 2,037  $ 29    3,423    3  $ 3,390  $ 30 
  Interest rate swaps   15       15       3       3    
  Foreign currency contracts               18       18    
  Cross-currency swaps   14       13    1    24       20    4 
 Total price risk management assets   2,097    2    2,065    30    3,468    3    3,431    34 
 NDT funds:                        
  Cash and cash equivalents   11    11          12    12       
  Equity securities                        
   U.S. large-cap   412    308    104       357    267    90    
   U.S. mid/small-cap   60    25    35       52    22    30    
  Debt securities                        
   U.S. Treasury   95    95          86    86       
   U.S. government sponsored agency   9       9       10       10    
   Municipality   82       82       83       83    
   Investment-grade corporate   40       40       38       38    
   Other   3       3       2       2    
  Receivables (payables), net      (2)   2          (3)   3    
 Total NDT funds   712    437    275       640    384    256    
 Auction rate securities (b)   19       3    16    24          24 
Total assets $ 3,864  $ 1,475  $ 2,343  $ 46  $ 5,543  $ 1,798  $ 3,687  $ 58 
                            
Liabilities                        
 Price risk management liabilities:                        
  Energy commodities $ 1,566  $ 2  $ 1,557  $ 7  $ 2,345    1  $ 2,327  $ 17 
  Interest rate swaps   80       80       63       63    
  Foreign currency contracts   44       44                
  Cross-currency swaps   4       4       2       2    
 Total price risk management liabilities $ 1,694  $ 2  $ 1,685  $ 7  $ 2,410    1  $ 2,392  $ 17 
                            
PPL Energy Supply                        
Assets                        
 Cash and cash equivalents $ 413  $ 413        $ 379  $ 379       
 Restricted cash and cash equivalents (a)   63    63          145    145       
 Price risk management assets:                        
  Energy commodities   2,068    2  $ 2,037  $ 29    3,423    3  $ 3,390  $ 30 
 Total price risk management assets   2,068    2    2,037    29    3,423    3    3,390    30 
 NDT funds:                        
  Cash and cash equivalents   11    11          12    12       
  Equity securities                        
   U.S. large-cap   412    308    104       357    267    90    
   U.S. mid/small-cap   60    25    35       52    22    30    
  Debt securities                        
   U.S. Treasury   95    95          86    86       
   U.S. government sponsored agency   9       9       10       10    
   Municipality   82       82       83       83    
   Investment-grade corporate   40       40       38       38    
   Other   3       3       2       2    
  Receivables (payables), net      (2)   2          (3)   3    
 Total NDT funds   712    437    275       640    384    256    
 Auction rate securities (b)   16       3    13    19          19 
Total assets $ 3,272  $ 915  $ 2,315  $ 42  $ 4,606  $ 911  $ 3,646  $ 49 
                            
Liabilities                        
 Price risk management liabilities:                        
  Energy commodities $ 1,566  $ 2  $ 1,557  $ 7  $ 2,345  $  1  $ 2,327  $ 17 
 Total price risk management liabilities $ 1,566  $ 2  $ 1,557  $ 7  $ 2,345  $  1  $ 2,327  $ 17 
363
     December 31, 2012 December 31, 2011
     Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
PPL Electric                        
Assets                        
 Cash and cash equivalents $ 140  $ 140        $ 320  $ 320       
 Restricted cash and cash equivalents (c)   13    13          13    13       
Total assets $ 153  $ 153        $ 333  $ 333       
LKE                        
Assets                        
 Cash and cash equivalents $ 43  $ 43        $ 59  $ 59       
 Restricted cash and cash equivalents (d)   32    32          29    29       
 Price risk management assets:                        
  Interest rate swaps   14     $ 14                
 Total price risk management assets   14       14                
Total assets $ 89  $ 75  $ 14     $ 88  $ 88       
                            
Liabilities                        
 Price risk management liabilities:                        
  Interest rate swaps (e) $ 58     $ 58     $ 60     $ 60    
 Total price risk management liabilities $ 58     $ 58     $ 60     $ 60    
                            
LG&E                        
Assets                        
 Cash and cash equivalents $ 22  $ 22        $ 25  $ 25       
 Restricted cash and cash equivalents (d)   32    32          29    29       
 Price risk management assets:                        
  Interest rate swaps   7     $ 7                
 Total price risk management assets   7       7                
Total assets $ 61  $ 54  $ 7     $ 54  $ 54       
                            
Liabilities                        
 Price risk management liabilities:                        
  Interest rate swaps (e) $ 58     $ 58     $ 60     $ 60    
 Total price risk management liabilities $ 58     $ 58     $ 60     $ 60    
                            
KU                        
Assets                        
 Cash and cash equivalents $ 21  $ 21        $ 31  $ 31       
 Price risk management assets:                        
  Interest rate swaps   7     $ 7                
 Total price risk management assets   7       7                
Total assets $ 28  $ 21  $ 7     $ 31  $ 31       

(a)Current portion is included in "Restricted cash and cash equivalents" and long-term portion is included in "Other noncurrent assets" on the Balance Sheets.
(b)Included in "Other investments" on the Balance Sheets.
(c)Current portion is included in "Other current assets" and the long-term portion is included in "Other noncurrent assets" on the Balance Sheets.
A reconciliation of net assets and liabilities classified as Level 3 for the years ended December 31, is as follows:
(d)Included in "Other noncurrent assets" on the Balance Sheets.
 Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
 2015 2014
 Energy Commodities, net Auction Rate Securities Total Energy Commodities, net Auction Rate Securities Total
Balance at beginning of period$111
 $8
 $119
 $24
 $16
 $40
Total realized/unrealized gains (losses)           
Included in earnings(91) —
 (91) (32) —
 (32)
Included in OCI—
 —
 —
 —
 1
 1
Purchases (a)(39) —
 (39) (6) —
 (6)
Sales65
 (2) 63
 67
 (9) 58
Settlements(24) —
 (24) 50
 —
 50
Transfers into Level 319
 —
 19
 7
 —
 7
Transfers out of Level 313
 —
 13
 1
 —
 1
Balance at end of period$54

$6

$60

$111

$8

$119
(e)Current portion is included in "Other current liabilities" on the Balance Sheets.  The long-term portion is included in "Price risk management liabilities" on the Balance Sheets.

A reconciliation of net assets and liabilities classified as Level 3 for the years ended is as follows:
                 
      PPL
      Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
      Energy Auction Cross-   
      Commodities, Rate Currency   
       net Securities Swaps Total
December 31, 2012            
Balance at beginning of period $ 13  $ 24  $ 4  $ 41 
  Total realized/unrealized gains (losses)            
    Included in earnings   2       (1)   1 
    Included in OCI (a)   1       1    2 
  Sales      (5)      (5)
  Settlements   (13)         (13)
  Transfers into Level 3   8          8 
  Transfers out of Level 3   11    (3)   (3)   5 
Balance at end of period $ 22  $ 16  $ 1  $ 39 
364
      PPL
      Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
      Energy Auction Cross-   
      Commodities, Rate Currency   
       net Securities Swaps Total
December 31, 2011            
Balance at beginning of period $ (3) $ 25     $ 22 
  Total realized/unrealized gains (losses)            
    Included in earnings   (65)         (65)
    Included in OCI (a)   (1)   (1) $ (10)   (12)
  Purchases   1          1 
  Sales   (3)         (3)
  Settlements   20          20 
  Transfers into Level 3   (10)      14    4 
  Transfers out of Level 3   74          74 
Balance at end of period $ 13  $ 24  $ 4  $ 41 

(a)"Energy Commodities" and "Cross-Currency Swaps" are included in "Qualifying derivatives" and "Auction Rate Securities" are included in "Available-for-sale securities" on2015 includes positions acquired through the Statementsacquisition of Comprehensive Income.RJS Power.

A reconciliation of net assets and liabilities classified as Level 3 for the years ended is as follows:
              
      PPL Energy Supply
      Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
      Energy Auction   
      Commodities, Rate   
       net Securities Total
December 31, 2012         
Balance at beginning of period $ 13  $ 19  $ 32 
  Total realized/unrealized gains (losses)         
    Included in earnings   2       2 
    Included in OCI (a)   1       1 
  Sales      (3)   (3)
  Settlements   (13)      (13)
  Transfers into Level 3   8       8 
  Transfers out of Level 3   11    (3)   8 
Balance at end of period $ 22  $ 13  $ 35 
              
December 31, 2011         
Balance at beginning of period $ (3) $ 20  $ 17 
  Total realized/unrealized gains (losses)         
    Included in earnings   (65)      (65)
    Included in OCI (a)   (1)   (1)   (2)
  Purchases   1       1 
  Sales   (3)      (3)
  Settlements   20       20 
  Transfers into Level 3   (10)      (10)
  Transfers out of Level 3   74       74 
Balance at end of period $ 13  $ 19  $ 32 

(a)
"Energy Commodities" are included in "Qualifying derivatives" and "Auction Rate Securities" are included in "Available-for-sale securities" on the Statements of Comprehensive Income.               

The significant unobservable inputs used in and quantitative information about the fair value measurement of assets and liabilities classified as Level 3 at December 31, 2012 are as follows:

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 December 31, 2015
Talen Energy
Fair Value, net
Asset
(Liability)
 
Valuation
Technique
 
 Significant Unobservable
Input(s)
 
Range
(Weighted
Average) (a)
Energy commodities       
Natural gas contracts (b)$55
 Discounted cash flow Proprietary model used to calculate forward prices 10% - 100% (50%)
Power sales contracts (c)13
 Discounted cash flow Proprietary model used to calculate forward prices 10% - 100% (100%)
FTR purchase contracts (d)(2) Discounted cash flow Historical settled prices used to model forward prices 100% (100%)
Heat rate call options (e)(10) Discounted cash flow Proprietary model used to calculate forward prices 100% (100%)
CRR purchase contracts (g)(2) Discounted cash flow Proprietary model used to calculate forward prices 100% (100%)
Auction rate securities (f)6
 Discounted cash flow Modeled from SIFMA Index 46% - 47% (46.5%)
Quantitative Information about Level 3 Fair Value Measurements
Fair Value, netRange
AssetValuationUnobservable(Weighted
(Liability)TechniqueInput(s)Average) (a)
PPL
Energy commodities
Retail natural gas sales contracts (b) 24 Discounted cash flowObservable wholesale prices used as proxy for retail delivery points21% - 100% (75%)
Power sales contracts (c) (4)Discounted cash flowProprietary model used to calculate forward basis prices24% (24%)
FTR purchase contracts (d) 2 Discounted cash flowHistorical settled prices used to model forward prices 100% (100%)
Auction rate securities (e) 16 Discounted cash flowModeled from SIFMA Index54% - 74% (64%)
Cross-currency swaps (f) 1 Discounted cash flowCredit valuation adjustment 22% (22%)
PPL Energy Supply
Energy commodities
Retail natural gas sales contracts (b) 24 Discounted cash flowObservable wholesale prices used as proxy for retail delivery points21% - 100% (75%)
Power sales contracts (c) (4)Discounted cash flowProprietary model used to calculate forward basis prices24% (24%)
FTR purchase contracts (d) 2 Discounted cash flowHistorical settled prices used to model forward prices100% (100%)
Auction rate securities (e) 13 Discounted cash flowModeled from SIFMA Index57% - 74% (65%)
 December 31, 2014
Talen Energy
Fair Value, net
Asset
(Liability)
 
Valuation
Technique
  Significant Unobservable
Input(s)		 
Range
(Weighted
Average) (a)
Energy commodities       
Natural gas contracts (b)$59
 Discounted cash flow Proprietary model used to calculate forward prices 11% - 100% (52%)
Power sales contracts (c)(1) Discounted cash flow Proprietary model used to calculate forward prices 10% - 100% (59%)
FTR purchase contracts (d)3
 Discounted cash flow Historical settled prices used to model forward prices 100% (100%)
Heat rate call options (e)50
 Discounted cash flow Proprietary model used to calculate forward prices 23% - 51% (45%)
Auction rate securities (f)8
 Discounted cash flow Modeled from SIFMA Index 51% - 69% (63%)

(a)For energy commodities and auction rate securities, theThe range and weighted average represent the percentage of fair value derived from the unobservable inputs.    For cross-currency swaps, the range and weighted average represent the percentage decrease in fair value due to the unobservable inputs used in the model to calculate the credit valuation adjustment.
(b)Retail natural gas sales contracts extend into 2017.  $11 million of the fair value is scheduled to deliver within the next 12 months.  As the forward price of natural gas increases/(decreases), the fair value of thepurchase contracts increases/(decreases)/increases.
(c)Power sales contracts extend into 2014.  $(4) million of the fair value is scheduled to deliver within the next 12 months..  As the forward price of basisnatural gas increases/(decreases), the fair value of sales contracts (decreases)/increases.    
(c)As forward market prices increase/(decrease), the fair value of contracts (decreases)/increases.  As volumetric assumptions for contracts in a gain position increase/(decrease), the fair value of contracts increases/(decreases).  As volumetric assumptions for contracts in a loss position increase/(decrease), the fair value of the contracts (decreases)/increases.
(d)FTR purchase contracts extend into 2015.  $2 million of the fair value is scheduled to deliver within the next 12 months.  As the forward implied spread increases/(decreases), the fair value of the contracts increases/(decreases).
(e)AuctionThe proprietary model used to calculate fair value incorporates market heat rates, correlations and volatilities.  As the market implied heat rate securities have a weighted average contractual maturityincreases/(decreases), the fair value of 23 years.  purchased calls increases/(decreases).   As the market implied heat rate increases/(decreases), the fair value of sold calls (decreases)/increases.    
(f)The model used to calculate fair value incorporates an assumption that the auctions will continue to fail.  As the modeled forward rates of the SIFMA Index increase/(decrease), the fair value of the securities increases/(decreases).
(f)Cross-currency swaps extend into 2017.  The credit valuation adjustment incorporates projected probabilities of default and estimated recovery rates.  
(g)As the credit valuation adjustmentforward implied spread increases/(decreases), the fair value of the swaps contracts increases/(decreases)/increases..  

Net gains and losses on assets and liabilities classified as Level 3 and included in earnings for the years ended December 31 wereare reported in the Statements of Income as follows:

    Cross-Currency
  Energy Commodities, net Swaps
               
  Unregulated Retail Wholesale Energy Net Energy Energy Interest
  Electric and Gas Marketing Trading Margins Purchases Expense
  2012  2011  2012  2011  2012  2011  2012  2011  2012  2011 
PPL                              
Total gains (losses) included in earnings $26  $32  $  (7)    $ (12) $ (1) $ (5) $ (96) $  (1)   
Change in unrealized gains (losses) relating to                              
 positions still held at the reporting date  29   23    (4) $ 5    1    1    1    (2)      
                                
PPL Energy Supply                              
Total gains (losses) included in earnings  26   32    (7)      (12)   (1)   (5)   (96)      
Change in unrealized gains (losses) relating to                              
 positions still held at the reporting date  29   23    (4)   5    1   1    1    (2)      
  Energy Commodities, net
  Wholesale Energy Retail Energy Energy Purchases
  2015 2014 2015 2014 2015 2014
Total gains (losses) included in earnings $(80) $(77) $(2) $23
 $(9) $22
Change in unrealized gains (losses) relating
to positions still held at the reporting date		 (7) 50
 29
 37
 (6) (4)

Price Risk Management Assets/Liabilities - Energy Commodities(PPL and PPL Energy Supply)

Energy commodity contracts are generally valued using the income approach, except for exchange-traded derivative gas and oil contracts, which are valued using the market approach and are classified as Level 1.  When the lowest level inputs that are significant to the fair value measurement of a contract are observable, the contract is classified as Level 2.  Level 2 contracts are valued using inputs which may include quotes obtained from an exchange (where there is insufficient market liquidity to warrant inclusion in Level 1), binding and non-binding broker quotes, prices posted by ISOs or published tariff rates.  Furthermore, independent quotes are obtained from the market to validate the forward price curves.  TheseEnergy commodity contracts include
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forwards, futures, swaps, options

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and structured transactions for electricity, gas, oil and/or emission allowances and may be offset with similar positions in exchange-traded markets.  To the extent possible, fair value measurements utilize various inputs that include quoted prices for similar contracts or market-corroborated inputs.  In certain instances, these contracts may be valued using models, including standard option valuation models and other standard industry models.  For example,When the lowest level inputs that are significant to the fair value measurement of a full-requirement sales contract that delivers power to an illiquid delivery point may be measured by valuingare observable, the nearest liquid trading point plus the value of the basis between the two points.  The basis input may be from market quotes or historical prices.contract is classified as Level 2.

When unobservable inputs are significant to the fair value measurement, a contract is classified as Level 3.  The fair value of contracts classified as Level 3 has been calculatedcontracts are valued using PPLTalen Energy's proprietary models which may include significant unobservable inputs such as delivery at a location where pricing is unobservable, assumptions for customer migration or delivery dates that are beyond the dates for which independent quotes are available.available, volumetric assumptions, implied volatilities, implied correlations, and market implied heat rates.  Forward transactions, including forward transactions classified as Level 3, are analyzed by PPL'sTalen Energy's Risk Management department, which reports to the Chief Financial Officer (CFO).department.  Accounting personnel who also report to the CFO, interpret the analysis quarterly to appropriately classify the forward transactionsfair value measurements in the fair value hierarchy.  Valuation techniques are evaluated periodically.  Additionally, Level 2 and Level 3 fair value measurements include adjustments for credit risk based on PPL'sTalen Energy's own creditworthiness (for net liabilities) and its counterparties' creditworthiness (for net assets).  PPL'sTalen Energy's credit department assesses all reasonably available market information which is used by accounting personnel to calculate the credit valuation adjustment.

In certain instances, energy commodity contracts are transferred between Level 2 and Level 3.  The primary reasons for the transfers during 2012 and 20112015 were changes in the availability of market information and changes in the significance of the unobservable inputs utilized in the valuation of the contract.  As the delivery period of a contract becomes closer, market information may become available.  When this occurs, the model's unobservable inputs are replaced with observable market information.

Price Risk Management Assets/Liabilities - Interest Rate Swaps/Foreign Currency Exchange Contracts/Cross-Currency Swaps (PPL, LKE, LG&E and KU)

To manage interest rate risk, PPL, LKE, LG&E and KU use interest rate contracts such as forward-starting swaps, floating-to-fixed swaps and fixed-to-floating swaps.  To manage foreign currency exchange risk, PPL uses foreign currency contracts such as forwards, options, and cross-currency swaps that contain characteristics of both interest rate and foreign currency contracts.         An income approach is used to measure the fair value of these contracts, utilizing readily observable inputs, such as forward interest rates (e.g., LIBOR and government security rates) and forward foreign currency exchange rates (e.g., GBP and Euro), as well as inputs that may not be observable, such as credit valuation adjustments.  In certain cases, market information cannot practicably be obtained to value credit risk and therefore internal models are relied upon.  These models use projected probabilities of default and estimated recovery rates based on historical observances.  When the credit valuation adjustment is significant to the overall valuation, the contracts are classified as Level 3.  The primary reason for the transfers during 2012 and 2011 was the change in the significance of the credit valuation adjustment.  Cross-currency swaps classified as Level 3 are valued by PPL's Corporate Finance department, which reports to the CFO.  Accounting personnel, who also report to the CFO, interpret analysis quarterly to appropriately classify the contracts in the fair value hierarchy.  Valuation techniques are evaluated periodically.

(PPL and PPL Energy Supply)

NDT Funds

The market approach is used to measure the fair value of equity securities held in theNDT funds.

·The fair value measurements of equity securities classified as Level 1 are based on quoted prices in active markets and are comprised of securities that are representative of the Wilshire 5000 Total Market Index.
The fair value measurements of equity securities classified as Level 1 are based on quoted prices in active markets.
The fair value measurements of investments in commingled equity funds are classified as Level 2.  These fair value measurements are based on firm quotes of net asset values per share, which are not obtained from a quoted price in an active market.

·Investments in commingled equity funds are classified as Level 2 and represent securities that track the S&P 500 Index, Dow Jones U.S. Total Stock Market Index and the Dow Jones U.S. Completion Total Stock Market Index.  These fair value measurements are based on firm quotes of net asset values per share, which are not obtained from a quoted price in an active market.

DebtThe fair value of debt securities areis generally measured using a market approach, including the use of matrix pricing.pricing models which incorporate observable inputs.  Common inputs include reported trades,benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities and credit valuation adjustments.  When necessary, the fair value of debt securities is measured using the income approach, which incorporates similar observable inputs as well as benchmark yields, credit valuation adjustments, referencepayment data, from market research publications, monthly payment data,future predicted cash flows, collateral performance and new issue data.
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The debt securities held by the NDT funds at December 31, 2012 have a weighted-average coupon of 4.11% and a weighted-average maturity of 8.26 years.

Auction Rate Securities

Auction rate securities include Federal Family Education Loan Program guaranteed student loan revenue bonds, as well as various municipal bond issues.  The exposure to realize losses on these securities is not significant.

The fair value of auction rate securities is estimated using an income approach that includes readily observable inputs, such as principal payments and discount curves for bonds with credit ratings and maturities similar to the securities, and unobservable inputs, such as future interest rates that are estimated based on the SIFMA Index, creditworthiness, and liquidity assumptions driven by the impact of auction failures.  The probability of realizing losses on these securities is not significant. When the present value of future interest payments is significant to the overall valuation, the auction rate securities are classified as Level 3.  The primary reason for the transfer out of Level 3 in 2012 was the change in the significance of the present value of future interest payments as maturity dates approach.

Auction rate securities are valued by PPL'sthe Treasury department, which reports to the CFO.department.  Accounting personnel who also report to the CFO, interpret the analysis quarterly to appropriately classify the contractsfair value measurements in the fair value hierarchy.  Valuation techniques are evaluated periodically.

Nonrecurring Fair Value Measurements(PPL, PPL Energy Supply, LKE and KU)

The following nonrecurring fair value measurements occurred during the reporting periods, resulting in asset impairments.impairments:            
 Carrying
Amount (a)		 Fair Value Measurements
Using Level 3 (b)		 Pre-tax Loss (c)
Sapphire plants (November 30, 2015)$270
 $204
 $66
Sapphire plants and C.P. Crane plant (September 30, 2015)388
 266
 122
Kerr Dam Project (March 31, 2014) (d)47
 29
 18
Corette plant and emission allowances (December 31, 2013)65
 —
 65

122

     Carrying Fair Value Measurements Using   
    Amount (a) Level 2 Level 3 Loss (b)
PPL, LKE and KU            
 Equity investment in EEI:            
  December 31, 2012 $ 25        $ 25 
PPL and PPL Energy Supply            
 Sulfur dioxide emission allowances (c):            
  December 31, 2010   2     $ 1    1 
  September 30, 2010   6       2    4 
  June 30, 2010   11       3    8 
  March 31, 2010   13       10    3 
 RECs (c):            
  September 30, 2011   1          1 
  June 30, 2011   2  $ 1       1 
  March 31, 2011   3          3 
 Certain non-core generation facilities:            
  September 30, 2010   473    381       96 
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(a)
Represents carrying value before fair value measurement.
(b)
For the Sapphire plants, also reflects estimated cost to sell at September 30, 2015.
(c)
The lossimpairment on the EEI investment was recorded in the Kentucky Regulated segment and included in "Other-Than-Temporary Impairments" on the Statement of Income.  Losses on sulfur dioxide emission allowances and RECs were recorded in the Supply segment and included in "Other operation and maintenance" on the Statements of Income.  Losses on certain non-core generation facilities were recorded in the Supply segment andKerr Dam Project is included in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statement of Income.
(c)Current The impairments on the C.P. Crane plant and long-term sulfur dioxide emission allowances and RECsthe Sapphire plants are included in "Other current assets" and "Other intangibles" in their respective areas"Impairments" on the Balance Sheets.Statement of Income.

(d)
The significant unobservable inputs usedKerr Dam Project was included in the sale of the Talen Montana hydroelectric facilities and the assets were removed from the Balance Sheet. See Note 6 for additional information.
The significant unobservable inputs used in and the quantitative information about the nonrecurring fair value measurement of assets and liabilities classified as Level 3 are as follows:
  Fair Value, net
Asset
(Liability)		 Valuation
Technique		 Significant
Unobservable
Input(s)		 Range
(Weighted
Average)(a)
 
 
 Sapphire plants (November 30, 2015)$204
 Discounted cash flow Proprietary model used to calculate plant value 100% (100%)
 Sapphire plants and C.P. Crane plant (September 30, 2015)266
 Discounted cash flow Proprietary model used to calculate plant value 100% (100%)
 Kerr Dam Project (March 31, 2014)29
 Discounted cash flow Proprietary model used to calculate plant value 38% (38%)
 Corette plant and emission allowances (December 31, 2013)—
 Discounted cash flow Long-term forward prices and a proprietary model used to calculate plant value 100% (100%)
(a)
The range and weighted average represent the percentage of fair value measurement of assets and liabilities classified as Level 3 at December 31, 2012 are as follows:
Quantitative Information about Level 3 Fair Value Measurements
Fair Value, netRange
AssetValuationUnobservable(Weighted
(Liability)TechniqueInput(s)Average)
PPL, LKE, and KU
Equity investment in EEI$Discounted cash flowLong-term forward price curves and capital expenditure projections100%  (100%)derived from the unobservable inputs.
           
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Equity Investment in EEI (PPL, LKESapphire Plants and KU)C.P. Crane Plant

DuringIn the fourththird quarter 2012, KUof 2015, Talen Energy updated its fundamental pricing models in conjunction with market information gained as a result of the 2018/2019 planning year PJM capacity auction completed in August 2015. As a result, Talen Energy assessed certain long-lived assets for impairment and determined that the C.P. Crane coal-fired plant failed a recoverability test and as a result, recorded an other-than-temporary declineimpairment charge based on the plant's estimated fair value at September 30, 2015. Additionally, because the Sapphire plants were classified as held for sale and had to be carried at the lower of their current carrying value or fair value less cost to sell, Talen Energy used updated cash flow information to calculate the estimated fair value of the Sapphire plants at September 30, 2015 and determined a write-down was necessary at that time based on estimated fair value. The Sapphire plants were reclassified from held for sale to held and used as of November 30, 2015 and updated cash flow information was used to calculate the estimated fair value on that date of reclassification to held and used and an additional write-down was necessary at that time based on the updated estimated fair value.

To estimate the fair value of the Sapphire plants and C.P. Crane plant, Talen Energy performed an internal analysis primarily using an income approach based on discounted cash flows (a proprietary Talen Energy model) to assess the fair value of these assets.  Assumptions used in the Talen Energy proprietary model were the forward energy and capacity price curves, forecasted generation, and forecasted operation, maintenance and capital expenditures and a market participant discount rate.  Through this analysis, Talen Energy determined the fair value of the C.P. Crane plant at September 30, 2015 and the Sapphire plants at September 30 and November 30, 2015. See Note 1 for additional information on the initial assets held for sale classification and subsequent reclassification to assets held and used for the Sapphire plants and Note 6 for additional information on the sale of the C.P. Crane plant.

The assets were valued by Talen Energy's financial planning and analysis personnel and accounting personnel interpreted the analysis to appropriately classify the fair value measurements in the fair value hierarchy.     
Kerr Dam Project

Talen Montana previously held a joint operating license issued for the Kerr Dam Project.  The license extends until 2035 and, between 2015 and 2025, the Confederated Salish and Kootenai Tribes of the Flathead Nation (the Tribes) have the option to purchase, hold and operate the Kerr Dam Project.  The parties submitted the issue of the appropriate amount of the conveyance price to arbitration in February 2013.  In March 2014, the arbitration panel issued its equity investment in EEI.  KUfinal decision holding that the conveyance price payable by the Tribes to Talen Montana was $18 million.  As a result of the decision, Talen Energy performed a recoverability test on the Kerr Dam Project and recorded an impairment charge. Talen Energy performed an internal analysis using an income approach based on discounted cash flows (a proprietary Talen Energy model) to assess the current fair value of its investment based on several factors.  KU considered the following factors:  long-datedKerr Dam Project.  Assumptions used in the Talen Energy proprietary model were the conveyance price, forward power and fuelenergy price curves, forecasted generation, and forecasted operation and maintenance expenditures that were consistent with assumptions used in the costbusiness planning process and a market participant discount rate.  Through this analysis, Talen Energy determined the estimated fair value of compliance with environmental standards,the Kerr Dam Project at March 31, 2014. The Kerr Dam Project was included in the November 2014 sale of the Talen Montana hydroelectric facilities. See Note 6 for additional information on the sale of the Talen Montana hydroelectric facilities.

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The assets were valued by the Talen Energy Financial Department. Accounting personnel interpreted the analysis to appropriately classify the assets in the fair value hierarchy.        

Corette Plant and the majority owner and operator's announcement inEmission Allowances

During the fourth quarter 20122013, Talen Montana recorded an impairment loss on the Corette plant and related emission allowances. In connection with the completion of its 2013 annual business planning process that included revised long-term power and gas price assumptions and other factors, Talen Energy altered its expectations regarding the probability that the Corette plant would operate subsequent to exit frominitially placing it in long-term reserve status and determined the merchant generation business.carrying amount for Corette was no longer recoverable. As a result, Talen Energy performed an internal analysis using an income approach based on discounted cash flows (a proprietary Talen Energy model) to assess the fair value of the Corette asset group. Assumptions used in the fair value assessment were forward energy price curves,prices, expectations for capacity (demand)demand for energy in EEI'sCorette's market and expected operation and maintenance and capital expenditures that were consistent with assumptions used in the calculation that were comparable to assumptions used by KU for internal budgetingbusiness planning process and forecasting purposes.a market participant discount rate. Through this analysis, KUTalen Energy determined the fair value of the asset group to be zero.negligible. Operations were suspended and the Corette plant was retired in the first quarter of 2015.

(PPL and PPLThe assets were valued by the Talen Energy Supply)

Sulfur Dioxide Emission Allowances

DueFinancial Department. Accounting personnel interpreted the analysis to declinesappropriately classify the assets in market prices, PPL Energy Supply assessed the recoverability of sulfur dioxide emission allowances not expected to be consumed.  When available, observable market prices were used to value the sulfur dioxide emission allowances.  When observable market prices were not available, fair value was modeled using prices from observable transactions and appropriate discount rates.  The modeled values were significant to the overall fair value measurement, resulting in the Level 3 classification.hierarchy.

RECs

Due to declines in forecasted full-requirement obligations in certain markets as well as declines in market prices, PPL Energy Supply assessed the recoverability of certain RECs not expected to be used.  Observable market prices (Level 2) were used to value the RECs.

Certain Non-Core Generation Facilities

Certain non-core generation facilities met the held for sale criteria at September 30, 2010.  As a result, net assets held for sale were written down to their estimated fair value less cost to sell.  The fair value in the table above excludes $4 million of estimated costs to sell and was based on the negotiated sales price (achieved through an active auction process).  See Note 9 for additional information on the completed sale.

Financial Instruments Not Recorded at Fair Value(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

The carrying amounts of contract adjustment payments related to the Purchase Contract component of the Equity Units and long-term debt on the Balance Sheets and theirits estimated fair values are set forth below.  The fair values of these instruments werevalue was primarily estimated using an income approach by discounting future cash flows at estimated current cost of funding rates, which incorporateincorporates the credit risk of the Registrants.  These instruments areTalen Energy Supply.  Long-term debt is classified as Level 2.           The effect of third-party credit enhancements is not included in the fair value measurement.

   December 31, 2012 December 31, 2011
   Carrying    Carrying   
   Amount Fair Value Amount Fair Value
PPL            
 Contract adjustment payments (a) $ 105  $ 106  $ 198  $ 198 
 Long-term debt   19,476    21,671    17,993    19,392 
PPL Energy Supply            
 Long-term debt   3,272    3,556    3,024    3,397 
PPL Electric            
 Long-term debt   1,967    2,333    1,718    2,012 
LKE            
 Long-term debt   4,075    4,423    4,073    4,306 
LG&E            
 Long-term debt   1,112    1,178    1,112    1,164 
KU            
 Long-term debt   1,842    2,056    1,842    2,000 
 December 31, 2015 December 31, 2014
 Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt$4,203
 $3,343
 $2,218
 $2,204

(a)Included in "Other current liabilities" and "Other deferred credits and noncurrent liabilities" on the Balance Sheets.
369
The carrying value of short-term debt, (including notes between affiliates), when outstanding, represents orand MACH Gen's Term Loan B approximates fair value due to the variable interest rates associated with the financial instrumentsdebt and is classified as Level 2.        The carrying value of held-to-maturity, short-term investments at December 31, 2011 approximated fair value due to the liquid nature and short-term duration of these instruments.

Credit Concentration Associated with Financial Instruments

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

Contracts are entered into with many entities for the purchase and sale of energy.  Many of these contracts qualify forWhen NPNS and, as such,is elected, the fair value of these contracts is not reflected in the financial statements.  However, the fair value of these contracts is considered when committing to new business from a credit perspective. See Note 1915 for information on credit policiesprocedures used to manage credit risk, including master netting arrangements and collateral requirements.

(PPL)

At December 31, 2012, PPL2015, Talen Energy had credit exposure of $1.8 billion$574 million from energy trading partners, excluding the effects of netting arrangements, reserves and collateral.  As a result of netting arrangements, reserves and collateral, PPL'sTalen Energy's credit exposure was reduced to $688$368 million.  The top ten counterparties, including their affiliates, accounted for $367$173 million, or 53%47%, of the net exposure and allthese exposures.  Nine of these counterparties had an investment grade credit ratingsrating from S&P or Moody's.

(PPL Energy Supply)

At December 31, 2012, PPL Energy Supply had credit exposureMoody's and accounted for 90% of $1.8 billion from energy trading partners, excluding exposure from related parties and the effects of netting arrangements and collateral.  As a result of netting arrangements and collateral, this credit exposure was reduced to $688 million.  The top ten counterparties accounted for $367 million, or 53%, of the net exposure and all had investment grade credit ratings fromexposures.  The remaining counterparty has not been rated by S&P or Moody's.  See Note 16 for information regarding the related party credit exposure.Moody's, but is current on its obligations.

(PPL Electric)

At December 31, 2012, PPL Electric had no credit exposure under energy supply contracts (including its supply contracts with PPL EnergyPlus).

(LKE, LG&E and KU)

At December 31, 2012, LKE's, LG&E's and KU's credit exposure was not significant.

19.
15.  Derivative Instruments and Hedging Activities

Risk Management Objectives

(PPL, PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU)

PPL has a risk management policy approved by the Talen Energy Corporation Board of Directors to manage market risk associated with commodities, interest rates on debt issuances and foreign exchange (including price, liquidity and volumetric risk) and credit risk (including non-performance risk and payment default risk).  The RMC,A risk management committee, comprised of senior management and chaired by the Chief Risk Officer,Director-Risk Management, oversees the risk management function.  Key risk control activities designed to ensure compliance with the risk policy and detailed programs include, but are not limited to, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, VaR analyses,analysis, portfolio stress tests, gross margincash flow at risk analyses,analysis, sensitivity analysesanalysis and daily portfolio reporting, including open positions, determinationsreporting.

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Market Risk

Market risk includes the potential loss that may be incurred as a result of price changes associated with a particular financial or commodity instrument as well as market liquidity and volumetric risks.  Forward contracts,and futures contracts, options, swaps and structured transactions such as tolling agreements, are utilized as part of risk management strategies to minimize unanticipated fluctuations in earnings caused by changes in commodity prices, volumes of full-requirement sales contracts, basis exposure and interest rates and/or foreign currency exchange rates. Many of the contracts meet the definition of a derivative.  All derivatives are recognized on the Balance Sheets at their fair value, unless they qualify for NPNS.NPNS is elected.

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The table below summarizes theTalen Energy is subject to market risks, that affect PPL and its subsidiaries.

PPLPPL
PPLEnergy SupplyElectricLKELG&EKU
Commodity price risk (including basis and
volumetric risk)XXMMMM
Interest rate risk:
Debt issuancesXXMMMM
Defined benefit plansXXMMMM
NDT securitiesXX
Equity securities price risk:
Defined benefit plansXXMMMM
NDT securitiesXX
Future stock transactionsX
Foreign currency risk - WPD investmentX

X= PPL and PPL Energy Supply actively mitigate market risks through their risk management programs described above.
M= The regulatory environments for PPL's regulated entities, by definition, significantly mitigate market risk.
which are actively mitigated through the risk management policy described above. Such risks include:

Commodity price risk, including basis and volumetric risksrisk
Interest rate risk

·PPL Energy Supply is exposed to commodity price, basis and volumetric risks for energy and energy-related products associated with the sale of electricity from its generating assets and other electricity and gas marketing activities (including full-requirement sales contracts) and the purchase of fuel and fuel-related commodities for generating assets, as well as for proprietary trading activities;
Commodity price risk
·PPL Electric is exposed to commodity price and volumetric risks from its obligation as PLR; however, its PUC-approved cost recovery mechanism substantially eliminates its exposure to market risk.  PPL Electric also mitigates its exposure to volumetric risk by entering into full-requirement supply agreements to serve its PLR customers.  These supply agreements transfer the volumetric risk associated with the PLR obligation to the energy suppliers; and

·LG&E's and KU's rates include certain mechanisms for fuel, gas supply and environmental expenses.  These mechanisms generally provide for timely recovery of market price and volumetric fluctuations associated with these expenses.
Talen Energy is exposed to commodity price risk for energy and energy-related products associated with the sale of electricity from its generating assets and other electricity and gas marketing activities and the purchase of fuel and fuel-related commodities for generating assets, as well as for proprietary trading activities.

Interest rate risk

·PPL and its subsidiaries areTalen Energy is exposed to interest rate risk associated with forecasted fixed-rate and existing floating-rate debt issuances.  WPD holds over-the-counter cross currency swaps to limit exposure to market fluctuations on interest and principal payments from foreign currency exchange rates.  LG&E utilizes over-the-counter interest rate swaps to limit exposure to market fluctuations on floating-rate debt and LG&E and KU utilize forward starting interest rate swaps to hedge changes in benchmark interest rates.

·PPL and its subsidiaries are exposed to interest rate risk associated with debt securities held by defined benefit plans.  Additionally, PPL Energy Supply is exposed to interest rate risk associated with debt securities held by the NDT.

Equity securities price risk

·PPL and its subsidiaries are exposed to equity securities price risk associated with equity securities held by defined benefit plans.  Additionally, PPL Energy Supply is exposed to equity securities price risk in the NDT funds.

·PPL is exposed to equity securities price risk from future stock sales and/or purchases.

Foreign currency risk

·PPL is exposed to foreign currency exchange risk primarily associated with its investments in U.K. affiliates.

Credit Risk

Credit risk is the potential loss that may be incurred due to a counterparty's non-performance, including defaults on payments and energy commodity deliveries.non-performance.

PPL is exposed to credit risk from "in-the-money" interest rate and foreign currency derivatives with financial institutions, as well as additional credit risk through certain of its subsidiaries, as discussed below.
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PPLTalen Energy Supply is exposed to credit risk from "in-the-money" commodity derivatives with its energy trading partners, which include other energy companies, fuel suppliers, financial institutions and financial institutions.

LKE, LG&Eother wholesale and KU are exposed to credit risk from "in-the-money" interest rate derivatives with financial institutions.retail customers.

The majority of Talen Energy's credit risk stems from commodity derivatives for multi-year contracts for energy sales and purchases.  If PPL Energy Supply'sTalen Energy's counterparties fail to perform their obligations under such contracts and PPLTalen Energy Supply could not replace the sales or purchases at the same or better prices as those under the defaulted contracts, PPLTalen Energy Supply would incur financial losses.  Those losses would be recognized immediately or through lower revenues or higher costs in future years, depending on the accounting treatment for the defaulted contracts.  In the event a supplier of LKE (through its subsidiaries LG&E and KU) or PPL Electric defaults on its obligation, those entities would be required to seek replacement power or replacement fuel in the market.  In general, incremental costs incurred by these entities would be recoverable from customers in future rates, thus mitigating the risk for these entities.

PPL and its subsidiaries haveTalen Energy has credit policiesprocedures in place to manage credit risk, including the use of an established credit approval process, daily monitoring of counterparty positions and the use of master netting agreements.agreements or provisions.  These agreements generally include credit mitigation provisions, such as margin, prepayment or collateral requirements.  PPL and its subsidiariesTalen Energy may request additional credit assurance, in certain circumstances, in the event that the counterparties' credit ratings fall below investment grade or their exposures exceed an established credit limit.  See Note 1814 for credit concentration associated with energy trading partners.

Master Netting Arrangements

Net derivative positions on the balance sheets are not offset against the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) under master netting arrangements.

PPL's and PPLTalen Energy Supply'sdid not have any obligation to return counterparty cash collateral under master netting arrangements was $112 million and $147 million at December 31, 20122015 and December 31, 2011.

PPL Electric, LKE, and LG&E had noan $11 million obligation to return cash collateral under master netting arrangements at December 31, 2012 and December 31, 2011.2014.

PPL, LKE and LG&E had posted cash collateral under master netting arrangements of $32 million at December 31, 2012 and $29 million at December 31, 2011.

PPLTalen Energy Supply and PPL Electric haddid not postedpost any cash collateral under master netting arrangements at December 31, 20122015 and December 31, 2011.2014.

(PPL and PPL Energy Supply)See "Offsetting Derivative Investments" below for a summary of derivative positions presented in the balance sheets where a right of setoff exists under these arrangements.

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Commodity Price Risk (Non-trading)

Commodity price risk, including basis and volumetric risk, is among PPL's and PPL Energy Supply'sTalen Energy's most significant risks due to the level of investment that PPL and PPLTalen Energy Supply maintainmaintains in theirits competitive generation assets, as well as the extent of their marketing activities.assets.  Several factors influence price levels and volatilities.  These factors include, but are not limited to, seasonal changes in demand, weather conditions, available generating assets within regions, transportation/transmission availability and reliability within and between regions, market liquidity, and the nature and extent of current and potential federal and state regulations.

PPLTalen Energy Supply maximizes the value of its wholesale and retail energy portfolios through the use of non-trading strategies that include sales of competitive baseload generation, optimization of competitive intermediate and peaking generation and marketing activities.

PPL Energy Supply has a formal hedging program to economically hedge the forecasted purchase and sale of electricity and related fuels for its competitive baseload generation fleet, which includes 7,275has a generation capacity of 17,379 MW (summer rating) of nuclear, coal and hydroelectric generating capacity.  PPL Energy Supply attempts to optimize the overall value of its competitive intermediate and peaking fleet, which.  Talen Energy's portfolio also includes 3,316 MW (summer rating) of natural gas and oil-fired generation.  PPL Energy Supply's marketing portfolio is comprised of full-requirement sales contracts and related supply contracts and retail natural gas and electricity sales contracts and other marketing activities.sale contracts. The strategies that PPLTalen Energy Supply uses to hedge its full-
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requirementfull-requirement sales contracts include supplying the energy, capacity and RECs from its generation assets and purchasing energy (at a liquid trading hub or directly at the load delivery zone), capacity and RECs in the market and/or supplying the energy, capacity and RECs from its generation assets.market.

PPL and PPLTalen Energy Supply enterenters into financial and physical derivative contracts, including forwards, futures, swaps and options, to hedge the price risk associated with electricity, natural gas, oil and other commodities.  Certain contracts qualify for NPNS or are non-derivatives or NPNS is elected and therefore they are therefore not reflected in the financial statements until delivery. PPL and PPLTalen Energy Supply segregate theirsegregates its non-trading activities into two categories:  cash flow hedges and economic activity.  In addition, the monetization of certain full-requirement sales contracts in 2010 impacted both the cash flow hedge and economic activity as discussed below.

Monetization of Certain Full-Requirement Sales Contracts

In July 2010, in order to raise additional cash for the LKE acquisition, PPL Energy Supply monetized certain full-requirement sales contracts that resulted in cash proceeds of $249 million and triggered certain accounting:

·A portion of these sales contracts had previously been accounted for as NPNS and received accrual accounting treatment.  PPL Energy Supply could no longer assert that it was probable that any contracts with these counterparties would result in physical delivery.  Therefore, the fair value of the NPNS contracts of $160 million was recorded on the Balance Sheet in "Price risk management assets," with a corresponding gain of $144 million recorded to "Wholesale energy marketing - Realized" on the Statement of Income, and $16 million recorded to "Wholesale energy marketing - Unrealized economic activity," related to full-requirement sales contracts that had not been monetized.

·  The related purchases to supply these sales contracts were accounted for as cash flow hedges, with the effective portion of the change in fair value being recorded in AOCI and the ineffective portion recorded in "Energy purchases - Unrealized economic activity."  The corresponding cash flow hedges were dedesignated and all amounts previously recorded in AOCI were reclassified to earnings.  This resulted in a pre-tax reclassification of $(173) million of losses from AOCI into "Energy purchases - Unrealized economic activity" on the Statement of Income.  An additional charge of $(39) million was also recorded in "Wholesale energy marketing - Unrealized economic activity" on the Statement of Income to reflect the fair value of the sales contracts previously accounted for as economic activity.

·The net result of these transactions, excluding the full-requirement sales contracts that have not been monetized, was a loss of $(68) million, or $(40) million, after tax.

The proceeds of $249 million from these monetizations are reflected in the Statement of Cash Flows as a component of "Net cash provided by operating activities."

Cash Flow Hedges

Certain derivative contracts have qualified for hedge accounting so that the effective portion of a derivative's gain or loss is deferred in AOCI and reclassified into earnings when the forecasted transaction occurs.  TheIn 2015 and 2014, there were no active cash flow hedges that existed at December 31, 2012 range in maturity through 2016.and there was no hedge ineffectiveness associated with energy derivatives. At December 31, 2012,2015, the accumulated net unrecognized after-tax gains (losses) that are expected to be reclassified into earnings during the next 12 months were $124 million for PPL and PPL Energy Supply.$12 million.  Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time periods and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedge transaction is probable of not occurring.  For 2012 and 2011There were no such reclassifications were insignificant.  For 2010, such reclassifications were after-tax gains (losses) of $(89) million.  The amounts recorded in 2010 were primarily due to the monetization of certain full-requirement sales contracts, for which the associated hedges are no longer required, as discussed above.2015, 2014 and 2013.

Hedge ineffectiveness associated with energy derivatives was insignificant in 2012.  For 2011 and 2010, after-tax gains (losses) from hedge ineffectiveness were $(22) million and $(30) million.

Prior to the adoption of new accounting guidance, in 2010, after-tax gains of $82 million, which had been recognized in a previous period due to ineffectiveness on cash flow hedges, were reversed from earnings based on prospective regression analysis demonstrating that these hedges were expected to be highly effective over their term.
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Economic Activity

Many derivative contracts economically hedge the commodity price risk associated with electricity, natural gas, oil and other commodities but do not receive hedge accounting treatment because they were not eligible for hedge accounting or for whichbecause hedge accounting was not elected.  These derivatives hedge a portion of the economic value of PPL Energy Supply'sTalen Energy's competitive generation assets and unregulatedcompetitive full-requirement and retail contracts, which are subject to changes in fair value due to market price volatility and volume expectations. Additionally, economic activity includes the ineffective portion of qualifying cash flow hedges (see "Cash Flow Hedges" above).  The derivative contracts in this category that existed at December 31, 20122015 range in maturity through 2019.2020.

Examples of economic activity may include hedges on sales of baseloadnuclear, coal and hydroelectric generation, certain purchase contracts used to supply full-requirement sales contracts, FTRs, CRRs, or basis swaps used to hedge basis risk associated with the sale of competitive generation or supplying unregulated full-requirement sales contracts, Spark Spread hedging contracts, retail electric and natural gas activities, and fuel oil swaps used to hedge price escalation clauses in coal transportation and other fuel-related contracts.  PPLTalen Energy Supply also uses options, which include the sale of call options and the purchase of put options tied to a particular generating unit.  Since the physical generating capacity is owned, price exposure is generally limited tocapped at the cost ofprice at which the generating unit would be dispatched and therefore does not expose PPLTalen Energy Supply to uncovered market price risk.

Unrealized activity associated with monetizing certain full-requirement sales contracts was also included in economic activity during 2012, 2011 and 2010.

The net fair value of economic positions at December 31, 2012 and December 31, 2011 was a net asset (liability) of $346 million and $(63) million for PPL and PPL Energy Supply.  The unrealized gains (losses) for economic activity for the years ended December 31 were as follows.

  2012  2011  2010 
       2015 2014 2013
Operating RevenuesOperating Revenues           
Unregulated retail electric and gas $ (17) $ 31  $ 1 
Wholesale energy marketing  (311)  1,407   (805)
Wholesale energy (a)$115
 $72
 $(267)
Retail energy(9) 29
 12
Operating ExpensesOperating Expenses           
Fuel  (14)  6   29 
Energy purchases  442   (1,123)  286 
Fuel15
 (27) (4)
Energy purchases (a)60
 (74) 132

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The net gains (losses) recorded in "Wholesale energy marketing" resulted primarily from hedgesTable of baseload generation, from certain full-requirement sales contracts, from hedge ineffectiveness, as discussed in "Cash Flow Hedges" above, and from the monetization of certain full-requirement sales contracts in 2010, also discussed above.  The net gains (losses) recorded in "Energy purchases" resulted primarily from certain purchase contracts to supply the full-requirement sales contracts noted above, from hedge ineffectiveness, and from purchase contracts that no longer hedge the full-requirement sales contracts that were monetized in 2010.Contents


(PPL and PPL Energy Supply)
(a)In the third quarter of 2015, Talen Energy refined an input used in its valuation technique for certain PJM basis curves as observable inputs became available. This change resulted in the recording of a $30 million net unrealized gain, primarily reflected in "Wholesale energy" revenue on the Statement of Income.

Commodity Price Risk (Trading)

PPLTalen Energy Supply also has a proprietary trading strategy which is utilized to take advantage of market opportunities.opportunities primarily in its geographic footprint.  As a result, PPLTalen Energy Supply may at times create a net open position in its portfolio that could result in significant losses if prices do not move in the manner or direction anticipated.  The proprietary trading portfolio is not a significant part of PPL Energy Supply's business and is shown in "NetNet energy trading margins"margins, which are included in "Wholesale energy" on the Statements of Income.Income, were $75 million in 2014 and insignificant for 2015 and 2013.

Commodity Volumetric ActivityVolumes

As ofAt December 31, 2012,2015, the net notional volumes of derivative (sales)/purchase contracts used in support of the various strategies discussed above were as follows.

   Volume   Volumes (a)
Commodity Unit of Measure 2013  2014  2015  Thereafter Unit of Measure 2016 2017 2018 Thereafter
          
Power MWh  (38,791,951)  (16,720,361)  1,636,197   3,871,199  MWh (36,420,569) (4,474,975) (568,082) (334,101)
Capacity MW-Month  (8,248,465)  (135,110)  (37,208)  525  MW-Month (5,953) 6
 3
 —
Gas MMBtu  18,419,599   (21,663,269)  (10,386,745)  (5,027,288) MMBtu 146,474,333
 17,898,993
 14,987,372
 3,063,441
Coal Tons  (240,000)      
FTRs MW-Month  28,690   6,389   1,465    MW-Month 8,724
 200
 —
 —
Oil Barrels  (4,022,000)  240,000   300,000   180,000  Barrels 65,559
 —
 —
 —
CRRs MWh 2,491,444
 538,584
 —
 —
Emission Allowances Tons 75,617
 —
 —
 —

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Interest Rate Risk
(a)Volumes for option contracts factor in the probability of an option being exercised and may be less than the notional amount of the option.   

(PPL, LKE, LG&E and KU)

PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk.  Various financial derivative instruments are utilized to adjust the mix of fixed and floating interest rates in their debt portfolio, adjust the duration of the debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate.  Risk limits under PPL's risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of the subsidiaries' debt portfolio due to changes in benchmark interest rates.

Cash Flow Hedges

(PPL)

Interest rate risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financings.  Financial interest rate swap contracts that qualify as cash flow hedges may be entered into to hedge floating interest rate risk associated with both existing and anticipated debt issuances.  Outstanding interest rate swap contracts ranged in maturity through 2024 for WPD and through 2043 for PPL's domestic interest rate swaps.  These swaps had an aggregate notional value of $1.2 billion at December 31, 2012, of which £290 million (approximately $465 million based on spot rates) was related to WPD.  Included in this total are forward-starting interest rate swaps entered into by PPL on behalf of LG&E and KU.  LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities.  The gains and losses will be recognized in "Interest Expense" on the Statements of Income over the life of the underlying debt when the hedged transaction occurs.

PPL holds a notional position in cross-currency interest rate swaps totaling $1.3 billion that mature through 2028 to hedge the interest payments and principal of WPD's U.S. dollar-denominated senior notes.

For 2012, hedge ineffectiveness associated with interest rate derivatives was insignificant.  For 2011, hedge ineffectiveness associated with these derivatives resulted in a net after-tax gain (loss) of $(9) million, which included a gain (loss) of $(4) million attributable to certain interest rate swaps that failed hedge effectiveness testing during the second quarter of 2011.  For 2010, hedge ineffectiveness associated with these derivatives resulted in a net after-tax gain (loss) of $(9) million.

Cash flow hedges are discontinued if it is no longer probable that the original forecasted transaction will occur by the end of the originally specified time periods and any amounts previously recorded in AOCI are reclassified into earnings once it is determined that the hedged transaction is probable of not occurring.  PPL had no such reclassifications for 2012 and 2011.  As a result of the expected net proceeds from the anticipated sale of certain non-core generation facilities, coupled with the monetization of certain full-requirement sales contracts, debt that had been planned to be issued by PPL Energy Supply in 2010 was no longer needed.  As a result, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued.  PPL reclassified into earnings a net after-tax gain (loss) of $(19) million in 2010.

At December 31, 2012, the accumulated net unrecognized after-tax gains (losses) on qualifying derivatives that are expected to be reclassified into earnings during the next 12 months were $(13) million.  Amounts are reclassified as the hedged interest payments are made.

(LKE, LG&E and KU)

In November 2012, LG&E and KU entered into forward-starting interest rate swaps with PPL that hedge the interest payments on new debt that is expected to be issued in 2013.  These hedging instruments have terms identical to forward-starting swaps entered into by PPL with third parties.  LG&E and KU believe that realized gains and losses from the swaps are probable of recovery through regulated rates; as such, the fair value of these derivatives have been reclassified from AOCI to regulatory assets or liabilities.  The gains and losses will be recognized in "Interest Expense" on the Statements of Income over the life of the underlying debt when the hedged transaction occurs.  At December 31, 2012, LG&E and KU each held contracts with aggregate notional amounts of $150 million that range in maturity through 2043.

(PPL Energy Supply)

In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.  Therefore, effective January 2011, PPL Energy Supply is no longer subject to interest rate risk associated with investments in U.K. affiliates.  For 2010, hedge ineffectiveness associated with these derivatives was insignificant for
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interest rate cross-currency swaps contracts.  For 2010, PPL Energy Supply had no reclassifications for cash flows hedges that were discontinued when it was no longer probable that the original forecasted transaction would occur by the end of the originally specified period.
Fair Value Hedges

(PPL)

PPL is exposed to changes in the fair value of its debt portfolio.  To manage this risk, financial contracts may be entered into to hedge fluctuations in the fair value of existing debt issuances due to changes in benchmark interest rates.  In July 2012, contracts held by PPL that ranged in maturity through 2047 and had a notional value of $99 million were canceled without penalties by the counterparties. PPL did not hold any such contracts at December 31, 2012.  PPL did not recognize gains or losses resulting from the ineffective portion of fair value hedges or from a portion of the hedging instrument being excluded from the assessment of hedge effectiveness or from hedges of debt issuances that no longer qualified as fair value hedges for 2012, 2011 and 2010.

In 2011, PPL Electric redeemed $400 million of 7.125% Senior Secured Bonds due 2013.  As a result of this redemption, PPL recorded a gain (loss) of $22 million, or $14 million after tax, for 2011 in "Other Income (Expense) - net" on the Statement of Income as a result of accelerated amortization of the fair value adjustments to the debt in connection with previously settled fair value hedges.

(PPL Energy Supply)

In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.  Therefore, effective January 2011, PPL Energy Supply is no longer subject to interest rate risk associated with investments in U.K. affiliates.  PPL Energy Supply did not recognize gains or losses resulting from the ineffective portion of fair value hedges or from a portion of the hedging instrument being excluded from the assessment of hedge effectiveness or resulting from hedges of debt issuances that no longer qualified as fair value hedges for 2010.

Economic Activity(PPL, LKE and LG&E)

LG&E enters into interest rate swap contracts that economically hedge interest payments on variable rate debt.  Because realized gains and losses from the swaps, including a terminated swap contract, are recoverable through regulated rates, any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities until they are realized as interest expense.  Realized gains and losses are recognized in "Interest Expense" on the Statements of Income when the hedged transaction occurs.  At December 31, 2012, LG&E held contracts with aggregate notional amounts of $179 million that range in maturity through 2033.  The fair value of these contracts were recorded as liabilities of $58 million and $60 million at December 31, 2012 and 2011, with equal offsetting amounts recorded as regulatory assets.

Foreign Currency Risk

(PPL)

PPL is exposed to foreign currency risk, primarily through investments in U.K. affiliates.  PPL has adopted a foreign currency risk management program designed to hedge certain foreign currency exposures, including firm commitments, recognized assets or liabilities, anticipated transactions and net investments.  In addition, PPL enters into financial instruments to protect against foreign currency translation risk of expected earnings.

Net Investment Hedges

PPL enters into foreign currency contracts on behalf of a subsidiary to protect the value of a portion of its net investment in WPD.  The contracts outstanding at December 31, 2012 had an aggregate notional amount of £162 million (approximately $261 million based on contracted rates).  The settlement dates of these contracts range from May 2013 through December 2013.  At December 31, 2012 and 2011, the fair value of these positions was a net asset (liability) of $(2) million and $7 million.

Additionally, in 2012, a PPL Global subsidiary that has a U.S. dollar functional currency entered into a GBP intercompany loan payable with a PPL WEM subsidiary that has a GBP functional currency.  The loan qualifies as a net investment hedge for the PPL Global subsidiary.  As such, the foreign currency gains and losses on the intercompany loan for the PPL Global subsidiary are recorded to the foreign currency translation adjustment component of AOCI.  At December 31, 2012, the intercompany loan outstanding was £47 million (approximately $76 million based on spot rates).
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For 2012, PPL recognized after-tax net investment hedge gains (losses) of $(5) million in the foreign currency translation adjustment component of AOCI.  For 2011 and 2010, PPL recognized after-tax net investment hedge gains (losses) of $4 million in the foreign currency translation adjustment component of AOCI.  At December 31, 2012 and 2011, PPL had $14 million and $19 million of accumulated net investment hedge after-tax gains (losses) that were included in the foreign currency translation adjustment component of AOCI.

(PPL Energy Supply)

In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.  Therefore, effective January 2011, PPL Energy Supply is no longer subject to foreign currency exchange risk associated with investments in U.K. affiliates.  For 2010, PPL Energy Supply recognized insignificant amounts in the foreign currency translation adjustment component of AOCI.

Cash Flow Hedges

(PPL)

PPL may enter into foreign currency derivatives associated with foreign currency-denominated debt and the exchange rate associated with firm commitments (including those for the purchase of equipment) denominated in foreign currencies; however, at December 31, 2012, there were no existing contracts of this nature.  Amounts previously settled and recorded in AOCI are reclassified as the hedged interest payments are made and as the related equipment is depreciated.  Insignificant amounts are expected to be reclassified into earnings during the next 12 months.

During 2012, 2011 and 2010, no cash flow hedges were discontinued because it was probable that the original forecasted transaction would not occur by the end of the originally specified time periods.

Fair Value Hedges

PPL enters into foreign currency forward contracts to hedge the exchange rate risk associated with firm commitments denominated in foreign currencies; however, at December 31, 2012, there were no existing contracts of this nature and no gains or losses recorded for 2012, 2011 and 2010 related to hedge ineffectiveness, or from a portion of the hedging instrument being excluded from the assessment of hedge effectiveness, or from hedges of firm commitments that no longer qualified as fair value hedges.

Economic Activity

PPL enters into foreign currency contracts on behalf of a subsidiary to economically hedge GBP-denominated anticipated earnings.  At December 31, 2012, the total exposure hedged by PPL was approximately £1.3 billion (approximately $2.0 billion based on contracted rates) and the net fair value of these positions was an asset (liability) of $(42) million.  These contracts had termination dates ranging from January 2013 through February 2015.  Realized and unrealized gains (losses) on these contracts are included in "Other Income (Expense) - net" on the Statements of Income and were $(52) million for 2012.  At December 31, 2011, the total exposure hedged by PPL was £288 million and the net fair value of these positions was an asset (liability) of $11 million.  Realized and unrealized gains (losses) were $10 million for 2011 and insignificant for 2010.

In anticipation of the repayment of a portion of the GBP-denominated borrowings under the 2011 Bridge Facility with U.S. dollar proceeds received from PPL's issuance of common stock and 2011 Equity Units and PPL WEM's issuance of U.S. dollar-denominated senior notes, PPL entered into forward contracts to purchase GBP in order to economically hedge the foreign currency exchange rate risk related to the repayment.  When these trades were settled in April 2011, PPL recorded $55 million of pre-tax, net gains (losses) in "Other Income (Expense) - net" on the Statements of Income.

(PPL Energy Supply)

In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.  Therefore, effective January 2011, PPL Energy Supply is no longer subject to earnings denominated in British pounds sterling.  PPL Energy Supply recorded gains (losses) on these contracts, both realized and unrealized, in "Income (Loss) from Discontinued Operations (net of income taxes)" on the Statements of Income.  For 2010, PPL Energy Supply recorded insignificant gains (losses).
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Accounting and Reporting

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)

All derivative instruments are recorded at fair value on the Balance Sheet as an asset or liability unless they qualify for NPNS.NPNS is elected.  NPNS contracts for PPL and PPLTalen Energy Supply include certain full-requirement sales contracts, other physical purchasespurchase and sales contracts and certain retail energy and physical capacity contracts, and for PPL Electric include full-requirement purchase contracts and other physical purchase contracts.  Changes in the fair value of derivatives not designated as NPNS are recognized currently in earnings unless specificearnings. Talen Energy has many physical and financial commodity purchases and sales contracts that economically hedge accounting criteriacommodity price risk.  Certain of the economic hedging strategies employed by Talen Energy utilize a combination of financial purchases and sales contracts. Realized and unrealized gains (losses) on these contracts are met, except for the changesrecorded currently in fair valueearnings.  Generally each contract is considered a unit of LG&E'saccount and KU's interest rate swaps, which beginning in the third quarter of 2010,Talen Energy presents gains (losses) on physical and financial commodity contracts based upon their economic hedging strategy. Generation revenue hedge strategies are recognized as regulatory assets or liabilities.  See Note 6 for amounts recorded in regulatory assets at December 31, 2012"Wholesale energy" on the Statements of Income. Retail sales strategies are recorded in "Retail energy" on the Statements of Income.  Gas, oil and 2011.coal generation supply strategies are recorded in "Fuel" on the Statements of Income. Non-generation power and fuel supply strategies are recorded in "Energy purchases" on the Statements of Income. Certain Talen Energy subsidiaries participate in RTOs and ISOs. Talen Energy accounts for these transactions on a net hourly basis because the transactions are settled on a net hourly basis. Talen Energy records realized hourly net sales or purchases of physical power with RTOs and ISOs in its Statements of Income as "Wholesale energy" if in a net sales position and "Energy purchases" if in a net purchase position.

See Note 1 for additional information on accounting policies related to derivative instruments.

(PPL)

The following tables presenttable presents the fair value and location of commodity derivative instruments not designated as hedging instruments recorded on the Balance Sheets.
  December 31, 2015 December 31, 2014
  Assets Liabilities Assets Liabilities
Current:        
  Price Risk Management Assets/Liabilities: $562
 $431
 $1,079
 $1,024
Noncurrent:        
  Price Risk Management Assets/Liabilities: 131
 108
 239
 193
Total derivatives $693
 $539
 $1,318
 $1,217


       December 31, 2012 December 31, 2011
       Derivatives designated as Derivatives not designated Derivatives designated as Derivatives not designated
       hedging instruments as hedging instruments (a) hedging instruments as hedging instruments (a)
       Assets Liabilities Assets Liabilities Assets Liabilities Assets Liabilities
Current:                        
 Price Risk Management                        
  Assets/Liabilities (b):                        
   Interest rate swaps $ 14  $ 22     $ 5  $ 3  $ 3     $ 5 
   Cross-currency swaps      3             2       
   Foreign currency                        
    contracts      2       23    7     $ 11    
   Commodity contracts   59     $ 1,452    1,010    872    3    1,655    1,557 
     Total current   73    27    1,452    1,038    882    8    1,666    1,562 
Noncurrent:                        
 Price Risk Management                        
  Assets/Liabilities (b):                        
   Interest rate swaps   1          53             55 
   Cross-currency swaps   14    1          24          
   Foreign currency                        
    contracts            19             
   Commodity contracts   27       530    556    42    2    854    783 
     Total noncurrent   42    1    530    628    66    2    854    838 
Total derivatives $ 115  $ 28  $ 1,982  $ 1,666  $ 948  $ 10  $ 2,520  $ 2,400 
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(a)$300 million and $237 million of net gains associated with derivatives that were no longer designated as hedging instruments are recorded in AOCI at December 31, 2012 and 2011.
(b)Represents the location on the Balance Sheet.

The after-tax balancesTable of accumulated net gains (losses) (excluding net investment hedges) in AOCI were $132 million, $527 million and $695 million at December 31, 2012, 2011 and 2010.Contents

The following tables present the pre-tax effect of derivative instruments recognized in income, OCIincome.
    
Gain (Loss) Reclassified from AOCI into Income
(Effective Portion)
Derivative
Relationships
 Location of Gain (Loss) Recognized in Income on Derivative 2015 2014 2013
Cash Flow Hedges:        
Commodity contracts Wholesale energy $(3) $1
 $240
  Energy purchases 33
 31
 (58)
  Depreciation 1
 2
 2
  Discontinued operations —
 8
 23
  Total $31
 $42
 $207

Derivatives Not Designated as
Hedging Instruments
 
Location of Gain (Loss) Recognized in
Income on Derivative
 2015 2014 2013
Commodity contracts Wholesale energy $742
 $(505) $(9)
  Retail energy 22
 30
 25
  Fuel (6) (30) 2
  Energy purchases (452) 165
 40
  Discontinued operations —
 6
 14
  Total $306
 $(334) $72
Offsetting Derivative Instruments

Certain subsidiaries of Talen Energy have master netting arrangements or regulatorysimilar agreements in place including derivative clearing agreements with futures commission merchants (FCMs) to permit the trading of cleared derivative products on one or more futures exchanges.  The clearing arrangements permit a FCM to use and apply any property in its possession as a setoff to pay amounts or discharge obligations owed by a customer upon default of the customer and typically do not place any restrictions on the FCM's use of collateral posted by the customer.  Certain subsidiaries of Talen Energy also enter into agreements pursuant to which they trade certain energy and other products.  Under the agreements, upon termination of the agreement as a result of a default or other termination event, the non-defaulting party typically would have a right to offset amounts owed under the agreement against any other obligations arising between the two parties (whether under the agreement or not), whether matured or contingent and irrespective of the currency, place of payment or place of booking of the obligation.

Talen Energy has elected not to offset derivative assets and regulatory liabilities.liabilities and not to offset net derivative positions against the right to reclaim cash collateral pledged (an asset) or the obligation to return cash collateral received (a liability) under derivatives agreements.  The table below summarizes the energy commodities derivative positions presented in the balance sheets where a right of setoff exists under these arrangements and related cash collateral received or pledged.             
    Assets Liabilities
      Eligible for Offset     Eligible for Offset  
    Gross 
Derivative
Instruments
 Cash Collateral Received Net Gross 
Derivative
Instruments
 Cash Collateral Pledged Net
December 31, 2015 $693
 $437
 $74
 $182
 $539
 $437
 $30
 $72
                   
December 31, 2014 $1,318
 $1,060
 $10
 $248
 $1,217
 $1,060
 $58
 $99

 Derivatives in Hedged Items in Location of Gain      
 Fair Value Hedging Fair Value Hedging (Loss) Recognized Gain (Loss) Recognized Gain (Loss) Recognized
 Relationships Relationships in Income in Income on Derivative in Income on Related Item
            
2012           
 Interest rate swaps Fixed rate debt Interest Expense    $ 3 
            
2011           
 Interest rate swaps Fixed rate debt Interest Expense $ 2  $ 25 
     Other Income      
     (Expense) - net      22 
2010           
 Interest rate swaps Fixed rate debt Interest Expense $ 48  $ (6)
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             Gain (Loss) Recognized
             in Income on Derivative
     Derivative Gain   Gain (Loss) Reclassified (Ineffective Portion and
   Derivative (Loss) Recognized in Location of Gain (Loss) from AOCI into Income Amount Excluded from
   Relationships  OCI (Effective Portion) Recognized in Income (Effective Portion) Effectiveness Testing)
2012            
 Cash Flow Hedges:           
  Interest rate swaps $ (28) Interest Expense $ (18)   
        Other Income (Expense) - net   1    
  Cross-currency swaps   (15) Interest Expense   (2)   
        Other Income (Expense) - net   (23)   
  Commodity contracts   114  Wholesale energy marketing   891  $  (1)
        Depreciation   2    
        Energy purchases   (139)   (2)
 Total $ 71    $ 712  $ (3)
 Net Investment Hedges:           
  Foreign currency contracts $ (7)        
               
2011            
 Cash Flow Hedges:           
  Interest rate swaps $ (55) Interest Expense $ (13) $ (13)
  Cross-currency swaps   (35) Interest Expense   5    
        Other Income (Expense) - net   29    
  Commodity contracts   431  Wholesale energy marketing   835    (39)
        Fuel   1    
        Depreciation   2    
        Energy purchases   (243)   1 
 Total $ 341    $ 616  $ (51)
 Net Investment Hedges:           
  Foreign currency contracts $ 6         
               
2010            
 Cash Flow Hedges:           
  Interest rate swaps $ (145) Interest Expense $ (4) $ (17)
        Other Income (Expense) - net   (30)   
  Cross-currency swaps   25  Interest Expense   2    
        Other Income (Expense) - net   16    
  Commodity contracts   487  Wholesale energy marketing   680    (201)
        Fuel   2    
        Depreciation   2    
        Energy purchases   (458)   3 
 Total $ 367    $ 210  $ (215)
 Net Investment Hedges:           
  Foreign currency contracts $ 5         

Derivatives Not Designated as Location of Gain (Loss) Recognized in         
 Hedging Instruments  Income on Derivatives  2012   2011   2010 
            
Foreign currency contracts Other Income (Expense) - net $ (52) $ 65  $ 3 
Interest rate swaps Interest Expense   (8)   (8)   
Commodity contracts Utility      (1)   (2)
  Unregulated retail electric and gas   30    39    11 
  Wholesale energy marketing   1,191    1,606    (70)
  Net energy trading margins (a)   8    (6)   1 
  Fuel      (1)   12 
  Energy purchases   (965)   (1,493)   (405)
  Total $ 204  $ 201  $ (450)
            
Derivatives Not Designated as Location of Gain (Loss) Recognized as         
 Hedging Instruments Regulatory Liabilities/Assets  2012   2011    
            
Interest rate swaps Regulatory assets - noncurrent $ 1  $ (26)   
            
Derivatives Designated as Location of Gain (Loss) Recognized as         
 Cash Flow Hedges Regulatory Liabilities/Assets  2012   2011    
            
Interest rate swaps Regulatory liabilities - noncurrent $ 14       

(a)Differs from the Statement of Income due to intra-month transactions that PPL defines as spot activity, which is not accounted for as a derivative.

(PPL Energy Supply)

The following tables present the fair value and location of derivative instruments recorded on the Balance Sheets.
379
       December 31, 2012 December 31, 2011
       Derivatives designated as Derivatives not designated Derivatives designated as Derivatives not designated
       hedging instruments as hedging instruments (a) hedging instruments as hedging instruments (a)
       Assets Liabilities Assets Liabilities Assets Liabilities Assets Liabilities
Current:                        
 Price Risk Management                        
  Assets/Liabilities (b):                        
   Commodity contracts $ 59     $ 1,452  $ 1,010  $ 872  $ 3  $ 1,655  $ 1,557 
     Total current   59       1,452    1,010    872    3    1,655    1,557 
Noncurrent:                        
 Price Risk Management                        
  Assets/Liabilities (b):                        
   Commodity contracts   27       530    556    42    2    854    783 
     Total noncurrent   27       530    556    42    2    854    783 
Total derivatives $ 86     $ 1,982  $ 1,566  $ 914  $ 5  $ 2,509  $ 2,340 

(a)$300 million and $237 million of net gains associated with derivatives that were no longer designated as hedging instruments are recorded in AOCI at December 31, 2012 and 2011.
(b)Represents the location on the Balance Sheet.

The after-tax balances of accumulated net gains (losses) (excluding net investment hedges) in AOCI were $210 million, $605 million and $733 million at December 31, 2012, 2011 and 2010.  The December 31, 2011 AOCI balance reflects the effect of PPL Energy Supply's distribution of its membership interest in PPL Global to its parent, PPL Energy Funding.  See Note 9 for additional information.

The following tables present the pre-tax effect of derivative instruments recognized in income or OCI.  There were no gains (losses) on interest rate swaps for 2012.

Derivatives inHedged Items inLocation of Gain
Fair Value HedgingFair Value Hedging(Loss) RecognizedGain (Loss) RecognizedGain (Loss) Recognized
RelationshipsRelationshipsin Incomein Income on Derivativein Income on Related Item
2011 
Interest rate swapsFixed rate debtInterest Expense$ 2 
2010 
Interest rate swapsFixed rate debtInterest Expense$ 2 

             Gain (Loss) Recognized
             in Income on Derivative
     Derivative Gain   Gain (Loss) Reclassified (Ineffective Portion and
  Derivative (Loss) Recognized in Location of Gain (Loss) from AOCI into Income Amount Excluded from
  Relationships  OCI (Effective Portion) Recognized in Income (Effective Portion) Effectiveness Testing)
2012            
 Cash Flow Hedges:           
  Commodity contracts $ 114  Wholesale energy marketing $ 891  $ (1)
        Depreciation   2    
        Energy purchases   (139)   (2)
 Total $ 114    $ 754  $ (3)
               
2011            
 Cash Flow Hedges:           
  Commodity contracts $ 431  Wholesale energy marketing $ 835  $ (39)
        Fuel   1    
        Depreciation   2    
        Energy purchases   (243)   1 
 Total $ 431    $ 595  $ (38)
               
2010            
 Cash Flow Hedges:           
  Interest rate swaps   Discontinued Operations (net of      
        income taxes)    $ (3)
  Cross-currency swaps$ 25  Discontinued Operations (net of      
        income taxes) $ 18    
  Commodity contracts   487  Wholesale energy marketing   680    (201)
        Fuel   2    
        Depreciation   2    
        Energy purchases   (458)   3 
 Total $ 512    $ 244  $ (201)
 Net Investment Hedges:           
  Foreign currency contracts $ 5         
380
Derivatives Not Designated as Location of Gain (Loss) Recognized in         
 Hedging Instruments  Income on Derivatives  2012   2011   2010 
            
Foreign currency contracts Discontinued Operations         
   (net of income taxes)       $ 3 
Commodity contracts Unregulated retail electric and gas $ 30  $ 39    11 
  Wholesale energy marketing   1,191    1,606    (70)
  Net energy trading margins (a)   8    (6)   1 
  Fuel      (1)   12 
  Energy purchases   (965)   (1,493)   (405)
  Total $ 264  $ 145  $ (448)

(a)Differs from the Statement of Income due to intra-month transactions that PPL Energy Supply defines as spot activity, which is not accounted for as a derivative.

(LKE)

The following table presents the fair value and location of derivative instruments recorded on the Balance Sheets:

       December 31, 2012 December 31, 2011
       Derivatives designated as Derivatives not designated Derivatives designated as Derivatives not designated
       hedging instruments as hedging instruments hedging instruments as hedging instruments
Current: Assets Liabilities Assets Liabilities Assets Liabilities Assets Liabilities
 Other Current                        
  Assets/Liabilities (a):                        
   Interest rate swaps $ 14        $ 5           $ 5 
     Total current   14          5             5 
Noncurrent:                        
 Price Risk Management                        
  Assets/Liabilities (a):                        
   Interest rate swaps            53             55 
     Total noncurrent            53             55 
Total derivatives $ 14        $ 58           $ 60 

(a)Represents the location on the Balance Sheet.

The following tables present the pre-tax effect of derivative instruments recognized in income or regulatory assets and regulatory liabilities for the periods ended December 31, 2012, 2011 and 2010, for the Successor and Predecessor.

    Successor  Predecessor
        
Two Months
Ended
  
Ten Months
Ended
Derivatives Not Designated as Location of Gain (Loss) Recognized in December 31, December 31, December 31,  October 31,
 Hedging Instruments  Income on Derivatives 2012  2011  2010   2010 
                
Interest rate swaps Interest Expense $ (8) $ (8) $ (1)  $ (7)
Commodity contracts Operating Revenues      (1)   (2)    3 
  Total $ (8) $ (9) $ (3)  $ (4)
                
                
Derivatives Not Designated as Location of Gain (Loss) Recognized as         
 Hedging Instruments Regulatory Liabilities/Assets December 31, 2012 December 31, 2011
                
Interest rate swaps Regulatory assets - noncurrent $    1  $     (26)
                
                
Derivatives Designated as Location of Gain (Loss) Recognized as         
Cash Flow Hedges Regulatory Liabilities/Assets December 31, 2012 December 31, 2011
                
Interest rate swaps Regulatory liabilities - noncurrent $    14        

(LG&E)

The following table presents the fair value and location of derivative instruments recorded on the Balance Sheets:
381
       December 31, 2012 December 31, 2011
       Derivatives designated as Derivatives not designated Derivatives designated as Derivatives not designated
       hedging instruments as hedging instruments hedging instruments as hedging instruments
Current: Assets Liabilities Assets Liabilities Assets Liabilities Assets Liabilities
 Other Current                        
  Assets/Liabilities (a):                        
   Interest rate swaps $ 7        $ 5           $ 5 
     Total current   7          5             5 
Noncurrent:                        
 Price Risk Management                        
  Assets/Liabilities (a):                        
   Interest rate swaps            53             55 
     Total noncurrent            53             55 
Total derivatives $ 7        $ 58           $ 60 

(a)Represents the location on the balance sheet.

The following tables present the pre-tax effect of derivative instruments recognized in income or regulatory assets and regulatory liabilities for the periods ended December 31, 2012, 2011 and 2010, for the Successor and Predecessor.

    Successor  Predecessor
    Year Ended Year Ended Two Months Ended  
Ten Months
Ended
Derivatives Not Designated as Location of Gain (Loss) Recognized in December 31, December 31, December 31,  October 31,
 Hedging Instruments  Income on Derivatives 2012  2011  2010   2010 
                
Interest rate swaps Interest Expense $ (8) $ (8) $ (1)  $ (7)
Commodity contracts Operating Revenues      (1)   (2)    3 
  Total $ (8) $ (9) $ (3)  $ (4)
                
                
Derivatives Not Designated as Location of Gain (Loss) Recognized as         
 Hedging Instruments Regulatory Liabilities/Assets December 31, 2012 December 31, 2011
                
Interest rate swaps Regulatory assets - noncurrent $    1  $     (26)
                
                
Derivatives Designated as Location of Gain (Loss) Recognized as         
Cash Flow Hedges Regulatory Liabilities/Assets December 31, 2012 December 31, 2011
                
Interest rate swaps Regulatory liabilities - noncurrent $    7        

(KU)

At December 31, 2012, KU had interest rate swaps, which were designated as hedging instruments, of $7 million recorded in "Other current assets" on the Balance Sheet.  KU recognized a $7 million, pre-tax gain on the derivative instruments in "Noncurrent regulatory liabilities" at December 31, 2012.

Credit Risk-Related Contingent Features(PPL, PPL Energy Supply, LKE, LG&E and KU)

Certain derivative contracts contain credit risk-related contingent features which, when in a net liability position, would permit the counterparties to require the transfer of additional collateral upon a decrease in the credit ratings of PPL, PPL Energy Supply, LKE, LG&E, KU or certain of their subsidiaries.Talen Energy.  Most of these provisionsfeatures would require the transfer of additional collateral or permit the counterparty to terminate the contract if the applicable credit rating were to fall below investment grade.  Some of these provisionsfeatures also would allow the counterparty to require additional collateral upon each decreasedowngrade in the credit rating at levels that remain above investment grade.  In either case, if the applicable credit rating were to fall below investment grade, (i.e., below BBB- for S&P and Fitch, or Baa3 for Moody's), and assuming no assignment to an investment grade affiliate were allowed, most of these credit contingent provisionsfeatures require either immediate payment of the net liability as a termination payment or immediate and ongoing full collateralization on derivative instruments in net liability positions. Talen Energy's credit rating is currently below investment grade.


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Additionally, certain derivative contracts contain credit risk-related contingent provisionsfeatures that require adequate assurance of performance be provided if the other party has reasonable concerns regarding the performance of PPL'sTalen Energy's obligation under the contract.  A counterparty demanding adequate assurance could require a transfer of additional collateral or other security, including letters of credit, cash and guarantees from a creditworthy entity.  This would typically involve negotiations among
382
the parties.  However, amounts disclosed below represent assumed immediate payment or immediate and ongoing full collateralization for derivative instruments in net liability positions with "adequate assurance" provisions.features.

At December 31, 2012,2015, the effectvalue of a decrease in credit ratings below investment grade on derivative contracts in a net liability position that contain credit risk-related contingent features was $70 million. Collateral posted on those positions was $71 million and the additional potential collateral requirements, primarily related to further adequate assurance features, were $34 million, which is net of receivables and payables already recorded on the Balance Sheet.

16.  Goodwill and Other Asset Impairments

U.S. GAAP requires that a long-lived asset (or asset group) be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  Similarly, a goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that more likely than not the carrying amount of a reporting unit may be greater than its fair value.  During the second quarter of 2015, due to the impairment of its investment in PPL Energy Supply recorded by PPL (Talen Energy's former parent) at the time of the spinoff, coupled with, and, primarily driven by, Talen Energy Corporation's stock price at the spinoff date, Talen Energy's management concluded that these factors could be indicators of potential impairment with respect to certain long-lived assets and goodwill.  After considering additional information, Talen Energy determined that the undiscounted cash flows for potentially affected long-lived assets would not be directly impacted by these factors and therefore concluded that the undiscounted cash flows continued to exceed the carrying value and no further testing of long-lived assets was necessary in the second quarter.  Management also performed an interim goodwill impairment assessment as of June 1, 2015, the spinoff and acquisition date.  The goodwill impairment analysis is a two-step process.  The first step, used to identify potential impairment, is a comparison of the reporting unit's estimated fair value to its carrying value, including goodwill.  If the fair value of the reporting unit exceeds its carrying value, applicable goodwill is not considered to be impaired.  If the carrying value exceeds the fair value, there is an indication of impairment and the second step is performed to measure the amount of the impairment, if any.  The second step requires a company to calculate an implied fair value of goodwill based on a hypothetical purchase price allocation.  The East reporting unit, which is equivalent to the East segment, failed step one as of June 1, 2015.  The step two analysis was not able to be completed by the filing of the second quarter Form 10-Q. As provided for in the applicable accounting guidance, no goodwill impairment charge was recorded based on management's best estimate at that time, which was confirmed when the second quarter analysis was subsequently completed.

In the third quarter of 2015, Talen Energy updated its fundamental pricing models in conjunction with market information gained as a result of the 2018/2019 planning year PJM capacity auction completed in August 2015. As a result, Talen Energy assessed certain long-lived assets for impairment and determined that the C.P. Crane coal-fired plant failed a recoverability test and as a result, recorded an impairment charge based on the plant's estimated fair value at September 30, 2015. Additionally, because the Sapphire plants were classified as held for sale and must be carried at the lower of its current carrying value or fair value less cost to sell, Talen Energy used updated cash flow information to calculate the estimated fair value of the Sapphire plants at September 30, 2015 and recorded an impairment charge based on estimated fair value. At November 30, 2015, in connection with the Sapphire plants being reclassified to held and used and continuing operations from held for sale and discontinued operations, management reassessed the fair value of each facility and recorded additional impairment charges. See Note 14 for additional information on these fair value estimates and the resulting non-cash asset impairment charges.

In addition, management's forward view of energy and capacity prices in PJM used in its fundamental pricing models, along with the consideration of other market information, has put pressure on the recoverability assessment of Talen Energy's other coal-fired generation assets. In December 2015, based on the availability of new gas price forecasts, management updated its fundamental view for long-term power, capacity and gas prices. Based upon the change in this fundamental view, management tested its coal-fired generation located primarily within the PJM market for impairment and concluded that the plants were not impaired at December 31, 2015. The recoverability assessment is very sensitive to forward energy and capacity price assumptions as well as forecasted operation and maintenance and capital spending. Therefore, a further decline in forecasted long-term energy or capacity prices or changes in environmental laws requiring additional capital or operation and maintenance expenditures, could negatively impact Talen Energy's operations primarily at its PJM based coal-fired facilities and potentially result in impairment charges for some or all of the carrying value of these plants. The carrying value of Talen Energy's coal-fired generation assets was more than $3 billion as of December 31, 2015.

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Finally, Talen Energy Corporation's stock price declined significantly throughout the third quarter of 2015, indicating a significant change in the financial markets' view of the value of Talen Energy's business and/or the industry in which it operates and potential risks associated with an investment in Talen Energy Corporation's common stock.  As a result, Talen Energy management concluded that these factors could be indicators of goodwill impairment and reconsidered certain inputs incorporated in its assessment of fair value of both Talen Energy's overall business and the East reporting unit, where all of the goodwill was assigned. These inputs include risk premiums, growth rates, Talen Energy Corporation's stock price expectations and implied multiples from comparable companies' stock prices.  Based on this reassessment, the East reporting unit further declined in fair value, when compared to the value calculated in the second quarter of 2015 and again failed step one as of September 30, 2015.  The step two analysis was also completed during the third quarter and resulted in a net liability positionnon-cash goodwill impairment charge of $466 million pre-tax recorded for the East segment included within "Income (Loss) from Continuing Operations" in the Statement of Income for the year ended December 31, 2015. The impairment charge represented all of the goodwill reflected on the Balance Sheet. Most of the impaired goodwill is summarized as follows:not deductible for tax purposes and there is no cash tax benefit related to the impairment. To estimate the fair value of Talen Energy's overall business and the East reporting unit, Talen Energy performed an internal analysis using a combination of a market approach using comparable businesses and an income approach based on discounted cash flows. Assumptions used in the discounted cash flow model, in addition to those discussed above, were the forward energy and capacity price curves, forecasted generation, and forecasted operation, maintenance and capital expenditures and a market participant discount rate. The market approach primarily applies EBITDA multiples, based on the implied market value of comparable publicly traded companies, to Talen Energy's and the East reporting unit's EBITDA to determine estimated fair values. During the fourth quarter of 2015, Talen Energy recorded various adjustments to the purchase price allocation for the RJS Power acquisition resulting in an adjustment to the goodwill recognized for the acquisition, which resulted in an insignificant adjustment to the previously recorded goodwill impairment.

       PPL      
    PPL Energy Supply LKE LG&E
               
Aggregate fair value of derivative instruments in a net liability            
 position with credit risk-related contingent provisions $ 219  $ 142  $ 39  $ 39 
Aggregate fair value of collateral posted on these derivative instruments   39    7    32    32 
Aggregate fair value of additional collateral requirements in the event of            
 a credit downgrade below investment grade (a)   202   155    9   9 
The changes in carrying amount of Talen Energy's goodwill by segment for the years ended December 31 were as follows.

  East West Total
  2015 2014 2015 2014 2015 2014
Balance at beginning of period (a) $72
 $72
 $—
 $14
 $72
 $86
Goodwill recognized during the period (b) 393
 —
 —
 —
 393
 —
Allocation to discontinued operations (c) —
 —
 —
 (14) —
 (14)
Impairment (465) —
 —
 —
 (465) —
Balance at end of period (a) $—
 $72
 $—
 $—
 $—
 $72
(a)Includes the effect of net receivables and payables already recorded on the Balance Sheet.

20.  Goodwill and Other Intangible Assets
                            
Goodwill
                            
(PPL and PPL Energy Supply)
                            
The changes in the carrying amount of goodwill by segment were:
                            
     Kentucky Regulated U.K. Regulated Supply Total
     2012  2011  2012  2011  2012  2011  2012  2011 
PPL                        
Balance at beginning of period (a) $ 662  $ 662  $ 3,032  $ 679  $ 420  $ 420  $ 4,114  $ 1,761 
 Goodwill recognized during the period (b)         (14)   2,391          (14)   2,391 
 Effect of foreign currency exchange rates         58    (38)         58    (38)
Balance at end of period (a) $ 662  $ 662  $ 3,076  $ 3,032  $ 420  $ 420  $ 4,158  $ 4,114 
                            
PPL Energy Supply                        
Balance at beginning of period (a)          $ 679  $ 86  $ 86  $ 86  $ 765 
 Derecognition (c)            (679)            (679)
Balance at end of period (a)          $  $ 86  $ 86  $ 86  $ 86 

(a)
There were was no accumulated impairment lossesloss related to goodwill.goodwill at December 31, 2014 and $465 million at December 31, 2015.
(b)Represents goodwill recognized
Recognized as a result of the acquisition of WPD Midlands.RJS Power. See Note 106 for additional information.
(c)Represents
Goodwill allocated to the amountsale of goodwill derecognized as a result of PPL Energy Supply's distribution of its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.the Talen Montana hydroelectric generating facilities and written off. See Note 96 for additional information on the distribution.  Subsequentrelated to the distribution, PPL Energy Supply operates in a single reportable segment and reporting unit.sale.

In 2014 and 2013, Talen Energy also recorded impairments related to the Kerr Dam project and Corette plant, both in Montana. See Note 14 for additional information.

17. Other Intangible Assets

Other Intangibles
               
(PPL)
               
The gross carrying amount and the accumulated amortization of other intangible assets were:
               
    December 31, 2012 December 31, 2011
    Gross    Gross   
    Carrying Accumulated Carrying Accumulated
    Amount Amortization Amount Amortization
Subject to amortization:            
 Contracts (a) (b) (c) $ 408  $ 150  $ 611  $ 155 
 Land and transmission rights   284    113    263    110 
 Emission allowances/RECs (d) (e) (f)   17       20    
 Licenses and other (g)   287    39    265    35 
Total subject to amortization   996    302    1,159    300 
               
Not subject to amortization due to indefinite life:            
 Land and transmission rights   18       16    
 Easements (h)   220       199    
Total not subject to amortization due to indefinite life   238       215    
Total $ 1,234  $ 302  $ 1,374  $ 300 
The gross carrying amount and the accumulated amortization of other intangible assets were:
383
 December 31, 2015 December 31, 2014
 Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization
Land and transmission rights$16
 $13
 $17
 $14
Emission allowances/RECs (a)9
 
 10
  
Licenses and other (b) (c)325
 23
 270
 19
Total$350
 $36
 $297
 $33

(a)In 2012, intangible assets related to a tolling agreement were eliminated in consolidation as a result of the Ironwood Acquisition.  See Note 10 for additional information.
(b)Gross carrying amount for 2011 includes $10 million, which represents the fair value of customer contracts with terms favorable to market recognized as a result of the 2011 acquisition of WPD Midlands.  The weighted-average amortization period of these contracts was ten years at the acquisition date.  See Note 10 for additional information.
(c)The gross carrying amount includes $269 million of coal contracts related to LKE, which represents the fair value of contracts with termsIncludes emission allowances and RECs that are favorable to market recognized as a result of the 2010 acquisition of LKE by PPL.  An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact.  See Note 6 for additional information.
(d)PPL Energy Supply emission allowances/RECs are expensed when consumed or sold.  Consumption expense was $12 million, $16 million, and $45 million in 2012, 2011 and 2010.  Consumption expensesold; therefore, there is expected to be insignificant in future periods.no accumulated amortization.
(e)Includes emission allowances of LKE.  An offsetting regulatory liability is recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact.  The carrying amounts of these emission allowances were insignificant at December 31, 2012 and 2011.  Consumption related to these emission allowances was insignificant in 2012 and $11 million in 2011.
(f)During 2011, PPL recorded $7 million of impairment charges.  See Note 18 for additional information.
(g)(b)"Other" includes costs for the development of licenses, the most significant of which is the COLA. Amortization of these costs begins when the related asset is placed in service. See Note 86 for additional information on the COLA.
(h)Gross carrying amount for 2011
(c)
"Other" also includes $88 million, which represents the fair value of easements recognizedintangibles acquired as a resultpart of the 2011RJS Power acquisition of WPD Midlands.  See Note 10including $28 million for additional information.a pipeline lease that is being amortized over a 14 year period and $16 million for an ash site permit that is being amortized over a 22 year period.


130

Current intangible assets are included in "Other current assets" and long-term intangible assets are included in "Other intangibles" in their respective areas on the Balance Sheets.Table of Contents

Amortization expense, excluding consumption of emission allowances/RECs, was as follows:
          
   2012   2011   2010 
          
Intangible assets with no regulatory offset $ 14  $ 25  $ 24 
Intangible assets with regulatory offset   47    87    11 
Total $ 61  $ 112  $ 35 

Amortization expense for each of the next five years, excluding consumption of emission allowances/RECs, is estimated to be:
                
   2013   2014   2015   2016   2017 
                
Intangible assets with no regulatory offset $ 10  $ 10  $ 10  $ 8  $ 8 
Intangible assets with a regulatory offset   52    46    51    27    9 
Total $ 62  $ 56  $ 61  $ 35  $ 17 

(PPL Energy Supply)
               
The gross carrying amount and the accumulated amortization of other intangible assets were:
               
    December 31, 2012 December 31, 2011
    Gross    Gross   
    Carrying Accumulated Carrying Accumulated
    Amount Amortization Amount Amortization
Subject to amortization:            
 Contracts (a)       $ 203  $ 53 
 Land and transmission rights $ 17  $ 13    17    13 
 Emission allowances/RECs (b) (c)   13       15    
 Licenses and other (d)   277    35    255    30 
Total subject to amortization $ 307  $ 48  $ 490  $ 96 

(a)In 2012, intangible assets related to a tolling agreement were eliminated in consolidation as a result of the Ironwood acquisition.  See Note 10 for additional information.
(b)These emission allowances/RECs are expensed when consumed or sold.  Consumption expense was $12 million, $16 million, and $46 million in 2012, 2011, and 2010.  Consumption expense is expected to be insignificant in future periods.
(c)During 2011, PPL Energy Supply recorded $7 million of impairment charges.  See Note 18 for additional information.
(d)"Other" includes costs for the development of licenses, the most significant of which is the COLA.  Amortization of these costs begins when the related asset is placed in service.  See Note 8 for additional information on the COLA.

Current intangible assets are included in "Other current assets" and long-term intangible assets are presented as "Other intangibles" in their respective areas on the Balance Sheets.
384
Amortization expense, excluding consumption of emission allowances/RECs, was as follows:
          
   2012   2011   2010 
          
Amortization expense $ 9  $ 20  $ 20 

Amortization expense for each of the next five years, excluding consumption of emission allowances/RECs, is estimated to be:
                
   2013   2014   2015   2016   2017 
                
Estimated amortization expense $ 5  $ 5  $ 5  $ 3  $ 3 

(PPL Electric)
               
The gross carrying amount and the accumulated amortization of other intangible assets were:
               
    December 31, 2012 December 31, 2011
    Gross    Gross   
    Carrying Accumulated Carrying Accumulated
    Amount Amortization Amount Amortization
Subject to amortization:            
 Land and transmission rights $ 249  $ 99  $ 232  $ 96 
 Licenses and other   4    1    4    1 
Total subject to amortization   253    100    236    97 
               
Not subject to amortization due to indefinite life:            
 Land and transmission rights   18       16    
Total $ 271  $ 100  $ 252  $ 97 

Intangible assets are shown as "Intangibles" on the Balance Sheets.

Amortization expense for the years ended December 31, excluding consumption of emission allowances, RECs and RGGI credits of $44 million, $24 million and $23 million in 2015, 2014, and 2013, was insignificant in 2012, 2011as follows:
 2015 2014 2013
Amortization Expense$4
 $4
 $5

Amortization expense, excluding consumption of emission allowances and 2010, andRGGI credits is expected to be insignificant in future years.

(LKE)
               
The gross carrying amount and the accumulated amortization of other intangible assets were:
               
    December 31, 2012 December 31, 2011
    Gross    Gross   
    Carrying Accumulated Carrying Accumulated
    Amount Amortization Amount Amortization
Subject to amortization:            
 Coal contracts (a) $ 269  $ 128  $ 269  $ 89 
 Land and transmission rights (b)   18    1    14    1 
 Emission allowances (c)   4       5    
 OVEC power purchase agreement (d)   126    17    126    9 
Total subject to amortization $ 417  $ 146  $ 414  $ 99 

(a)Gross carrying amount represents the fair value of coal contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL.  An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact.  See Note 6 for additional information.
(b)Gross carrying amount includes $14 million, which represents the fair value of land and transmission rights recognized as an intangible asset as a result of adopting PPL's accounting policies in the Successor period. Amortization expense is recovered through base rates and is expected to be insignificant for future periods.
(c)Represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL.  An offsetting regulatory liability is recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact.  Consumption related to these emission allowances was insignificant in 2012 and $11 million in 2011.
(d)Gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL.  See Note 6 for additional information.

Current intangible assets are included in "Other current assets" on the Balance Sheets.  Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.
385
Amortization expense for the Successor, excluding consumption of emission allowances, was as follows:
          
   2012   2011   2010 
          
Intangible assets with no regulatory offset    $ 1    
Intangible assets with regulatory offset $ 47    87  $ 11 
Total $ 47  $ 88  $ 11 

Amortization expense for each of the next five years, excluding consumption of emission allowances, is estimated to be:
                
   2013   2014   2015   2016   2017 
                
Intangibles with regulatory offset $ 52  $ 46  $ 51  $ 27  $ 9 

(LG&E)
               
The gross carrying amount and the accumulated amortization of other intangible assets were:
               
    December 31, 2012 December 31, 2011
    Gross    Gross   
    Carrying Accumulated Carrying Accumulated
    Amount Amortization Amount Amortization
Subject to amortization:            
 Coal contracts (a) $ 124  $ 62  $ 124  $ 46 
 Land and transmission rights (b)   8    1    6    1 
 Emission allowances (c)   1       2    
 OVEC power purchase agreement (d)   87    13    87    6 
Total subject to amortization $ 220  $ 76  $ 219  $ 53 

(a)Gross carrying amount represents the fair value of coal contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL.  An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact.  See Note 6 for additional information.
(b)Gross carrying amount includes $6 million, which represents the fair value of land and transmission rights recognized as an intangible asset as a result of adopting PPL's accounting policies in the Successor period. Amortization expense is recovered through base rates and is expected to be insignificant for future periods.
(c)Represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL.  An offsetting regulatory liability is recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact.  Consumption related to these emission allowances was insignificant in 2012 and $5 million in 2011.
(d)Gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL.  See Note 6 for additional information.

Current intangible assets are included in "Other current assets" on the Balance Sheets.  Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.

Amortization expense for the Successor, excluding consumption of emission allowances, was as follows:
          
   2012   2011   2010 
          
Intangible assets with no regulatory offset    $ 1    
Intangible assets with regulatory offset $ 23    45  $ 7 
Total $ 23  $ 46  $ 7 

Amortization expense for each of the next five years, excluding consumption of emission allowances, is estimated to be:
                
   2013   2014   2015   2016   2017 
                
Intangibles with regulatory offset $ 25  $ 23  $ 24  $ 14  $ 6 

(KU)
The gross carrying amount and the accumulated amortization of other intangible assets were:
386
               
    December 31, 2012 December 31, 2011
    Gross    Gross   
    Carrying Accumulated Carrying Accumulated
    Amount Amortization Amount Amortization
Subject to amortization:            
 Coal contracts (a) $ 145  $ 66  $ 145  $ 43 
 Land and transmission rights (b)   10       8    
 Emission allowances (c)   3       3    
 OVEC power purchase agreement (d)   39    4    39    3 
Total subject to amortization $ 197  $ 70  $ 195  $ 46 

(a)Gross carrying amount represents the fair value of coal contracts with terms favorable to market recognized as a result of the 2010 acquisition by PPL.  An offsetting regulatory liability was recorded related to these contracts, which is being amortized over the same period as the intangible assets, eliminating any income statement impact.  See Note 6 for additional information.
(b)Gross carrying amount includes $8 million, which represents the fair value of land and transmission rights recognized as an intangible asset as a result of adopting PPL's accounting policies in the Successor period. Amortization expense is recovered through base rates and is expected to be insignificant for future periods.
(c)Represents the fair value of emission allowances recognized as a result of the 2010 acquisition by PPL.  An offsetting regulatory liability is recorded related to these emission allowances, which is being amortized as the emission allowances are consumed, eliminating any income statement impact.  Consumption related to these emission allowances was $6 million for 2011.  KU had no consumption related to these emission allowances in 2012.
(d)Gross carrying amount represents the fair value of the OVEC power purchase contract recognized as a result of the 2010 acquisition by PPL.  See Note 6 for additional information.

Current intangible assets are included in "Other current assets" on the Balance Sheets.  Long-term intangible assets are presented as "Other intangibles" on the Balance Sheets.

Amortization expense for the Successor, excluding consumption of emission allowances, was as follows:
          
   2012   2011   2010 
          
Intangible assets with regulatory offset $ 24  $ 42  $ 4 

Amortization expense for each of the next five years, excluding consumption of emission allowances, is estimated to be:
                
   2013   2014   2015   2016   2017 
                
Intangibles with regulatory offset $ 27  $ 23  $ 27  $ 13  $ 3 
18.  Asset Retirement Obligations

21.  Asset Retirement Obligations

(PPL)

WPDTalen Energy has recorded conditional AROs required by U.K. law related to treated wood poles, gas-filled switchgear and fluid-filled cables.

(PPL and PPL Energy Supply)

PPL Energy Supply has recorded liabilities in the financial statements to reflect various legal obligations associated with the retirement of long-lived assets, the most significant of which relates to the decommissioning of the Susquehanna nuclear plant. The accrued nuclear decommissioning obligation was $316 million and $292 million at December 31, 2012 and 2011.  The fair value of investments thatAssets in the NDT funds are legally restricted for the decommissioningpurpose of the Susquehanna nuclear plant was $712 million and $640 million at December 31, 2012 and 2011, and is included in "Nuclear plant decommissioning trust funds" on the Balance Sheets.settling this ARO. See Notes 1814 and 2319 for additional information on the nuclear decommissioning trust funds. Other AROs recorded relate to various environmental requirements for coal piles, ash basins and other waste basin retirements.

PPLTalen Energy Supply has recorded several conditional AROs, the most significant of which is related to the removal and disposal of asbestos-containing material. In addition to the AROs that were recorded for asbestos-containing material, PPLTalen Energy Supply identified other asbestos-related obligations, but was unable to reasonably estimate their fair values. PPLTalen Energy Supply management was unable to reasonably estimate a settlement date or range of settlement dates for the remediation of all of the asbestos-containing material at certain of the generation plants. If economic events or other circumstances change that enable PPLTalen Energy Supply to reasonably estimate the fair value of these retirement obligations, they will be recorded at that time.

PPLTalen Energy Supply also identified legal retirement obligations associated with the retirement of a reservoir that could not be reasonably estimated due to an indeterminable settlement date.
387
(PPL and PPL Electric)

PPL Electric has identified legal retirement obligations for the retirement of certain transmission assets that could not be reasonably estimated due to indeterminable settlement dates.  These assets are located on rights-of-way that allow the grantor to require PPL Electric to relocate or remove the assets.  Since this option is at the discretion of the grantor of the right-of-way, PPL Electric is unable to determine when these events may occur.

(PPL, LKE, LG&E and KU)

LG&E's and KU's AROs are primarily related to the final retirement of assets associated with generating units.  LG&E also has AROs related to natural gas mains and wells.  LG&E's and KU's transmission and distribution lines largely operate under perpetual property easement agreements which do not generally require restoration upon removal of the property.  Therefore, no material AROs are recorded for transmission and distribution assets.  As described in Notes 1 and 6, the accretion and depreciation expense recorded by LG&E and KU is offset with a regulatory credit on the income statement, such that there is no earnings impact.

(PPL, PPL Energy Supply, LKE, LG&E and KU)

The changes in the carrying amounts of Talen Energy's AROs were as follows.

   PPL PPL Energy Supply
   2012  2011  2012  2011 
          2015 2014
ARO at beginning of periodARO at beginning of period $ 497  $ 448  $ 359  $ 345 $425
 $404
Accretion expense  36   33   28   26 
Obligations assumed in acquisition of WPD Midlands (a)    15     
Derecognition (b)        (5)
Obligations incurred  9   14   3   11 
Changes in estimated cash flow or settlement date  31   5   (7)  (1)
Effect of foreign currency exchange rates  1       
Obligations settled   (22)   (18)   (8)   (17)
Accretion expense35
 32
Changes in estimate of cash flow or settlement date (a)25
 (16)
Obligations assumed in RJS Power acquisition18
 —
Obligations incurred2
 13
Obligations settled(4) (8)
ARO at end of periodARO at end of period $ 552  $ 497  $ 375  $ 359 $501
 $425

                     
    LKE LG&E KU
    2012  2011  2012  2011  2012  2011 
                     
ARO at beginning of period $ 118  $ 103  $ 57  $ 49  $ 61  $ 54 
 Accretion expense   6    6    3    3    3    3 
 Obligations incurred   6    3       2    6    1 
 Changes in estimated cash flow                  
  or settlement date   15    7    5    4    10    3 
 Obligations settled   (14)   (1)   (3)   (1)   (11)   
ARO at end of period $ 131  $ 118  $ 62  $ 57  $ 69  $ 61 

(a)
Obligations required under U.K. law related to treated wood poles, gas-filled switchgear and fluid-filled cables.  See Note 10 for additional information on the acquisition.       
(b)(a)Represents AROs derecognizedIncludes increases in 2015 of $41 million as a result of PPL Energy Supply's distributiona new CCR rule. Further changes to the AROs may be required as estimates are refined and analysis of its membership interest in PPL Global to PPL Energy Supply's parent, PPL Energy Funding.  See Note 9 for additional information on the distribution.rule continues.

Substantially all of the ARO balances are classified as noncurrentnon-current at December 31, 20122015 and 2011.2014. 


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Table of Contents

19.  Available-for-Sale Securities

22.  Variable Interest Entities

(PPL and PPL Energy Supply)

In December 2001, a subsidiary of PPL Energy Supply entered into a $455 million operating lease arrangement, as lessee, for the development, construction and operation of a gas-fired combined-cycle generation facility located in Lower Mt. Bethel Township, Northampton County, Pennsylvania.  The owner/lessor of this generation facility, LMB Funding, LP, was created to own/lease the facility and incur the related financing costs.  The initial lease term commenced on the date of commercial operation, which occurred in May 2004, and ends in December 2013.  Under a residual value guarantee, if the generation facility is sold at the end of the lease term and the cash proceeds from the sale are less than the original acquisition cost, the subsidiary of PPL Energy Supply is obligated to pay up to 70.52% of the original acquisition cost.  This residual value guarantee protects the other variable interest holders from losses related to their investments.  LMB Funding, LP cannot
388
extend or cancel the lease or sell the facility without the prior consent of the PPL Energy Supply subsidiary.  As a result, LMB Funding, LP was determined to be a VIE and the subsidiary of PPL Energy Supply was considered the primary beneficiary that consolidates this VIE.

The lease financing, which includes $437 million of debt and $18 million of "Noncontrolling interests" at December 31, 2012 and December 31, 2011, is secured by, among other things, the generation facility, the carrying amount of which is disclosed on the Balance Sheets.  The debt matures in December 2013, the end of the initial lease term, and therefore has been classified in "Long-term debt due within one year" at December 31, 2012.  As a result of the consolidation, PPL Energy Supply has recorded interest expense in lieu of rent expense.  For 2012, 2011 and 2010, additional depreciation on the generation facility of $16 million was recorded each year.

23.  Available-for-Sale Securities

(PPL, PPL Energy Supply, LKE and LG&E)

Certain short-term investments, securities held by theTalen Energy's NDT funds and auction rate securities are classified as available-for-sale.

The following table shows the amortized cost, the gross unrealized gains and losses recorded in AOCI and the fair value of Talen Energy's available-for-sale securities.
 December 31, 2015 December 31, 2014
 
Amortized
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 Fair Value 
Amortized
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 Fair Value
NDT funds:               
Cash and cash equivalents$11
 $—
 $—
 $11
 $19
 $—
 $—
 $19
Equity securities297
 406
 —
 703
 283
 417
 —
 700
Debt securities230
 7
 —
 237
 218
 11
 —
 229
Receivables/payables, net—
 —
 —
 —
 2
 —
 —
 2
Total NDT funds$538
 $413
 $—
 $951
 $522
 $428
 $—
 $950
                
Auction rate securities$6
 $—
 $—
 $6
 $8
 $—
 $—
 $8

       December 31, 2012 December 31, 2011
          Gross Gross      Gross Gross  
       Amortized  Unrealized  Unrealized   Amortized  Unrealized  Unrealized  
       Cost Gains Losses Fair Value  Cost  Gains Losses Fair Value
PPL                        
 NDT funds:                        
   Cash and cash equivalents $ 11        $ 11  $ 12        $ 12 
   Equity securities:                        
    U.S. large-cap   222  $ 190       412    211  $ 146       357 
    U.S. mid/small-cap   30    30       60    29    23       52 
   Debt securities:                        
    U.S. Treasury   86    9       95    76    10       86 
    U.S. government sponsored                        
     agency   8    1       9    9    1       10 
    Municipality   78    5  $ 1    82    80    4  $ 1    83 
    Investment-grade corporate   36    4       40    35    3       38 
    Other   3          3    2          2 
   Total NDT funds   474    239    1    712    454    187    1    640 
 Auction rate securities   20       1    19    25       1    24 
 Total $ 494  $ 239  $ 2  $ 731  $ 479  $ 187  $ 2  $ 664 
                              
PPL Energy Supply                        
 NDT funds:                        
   Cash and cash equivalents $ 11        $ 11  $ 12        $ 12 
   Equity securities:                        
    U.S. large-cap   222  $ 190       412    211  $ 146       357 
    U.S. mid/small-cap   30    30       60    29    23       52 
   Debt securities:                        
    U.S. Treasury   86    9       95    76    10       86 
    U.S. government sponsored                        
     agency   8    1       9    9    1       10 
    Municipality   78    5  $ 1    82    80    4  $ 1    83 
    Investment-grade corporate   36    4       40    35    3       38 
    Other   3          3    2          2 
   Total NDT funds   474    239    1    712    454    187    1    640 
 Auction rate securities   17       1    16    20       1    19 
 Total $ 491  $ 239  $ 2  $ 728  $ 474  $ 187  $ 2  $ 659 
See Note 14 for details on the securities held by the NDT funds.

There were no securities with credit losses at December 31, 20122015 and 2011.2014.

The following table shows the scheduled maturity dates of debt securities held at December 31, 2012.2015.        
389
  Maturity Maturity Maturity Maturity   
   Less Than1-56-10in Excess 
  1 YearYearsYearsof 10 YearsTotal
Maturity
Less Than
1 Year
 
Maturity
1-5
Years
 
Maturity
6-10
Years
 
Maturity
in Excess
of 10 Years
 Total
PPL          
Amortized costAmortized cost $ 12  $ 79  $ 62  $ 78  $ 231 $7
 $101
 $67
 $61
 $236
Fair valueFair value  12   83   68   85   248 7
 102
 69
 65
 243
           
PPL Energy Supply          
Amortized cost $ 12  $ 79  $ 62  $ 75  $ 228 
Fair value  12   83   68   82   245 

The following table shows proceeds from and realized gains and losses on sales of available-for-sale securities.
           
   2012  2011  2010 
PPL         
Proceeds from sales of NDT securities (a) $ 139  $ 156  $ 114 
Other proceeds from sales   5    163    
Gross realized gains (b)   29    28    13 
Gross realized losses (b)   21    16    5 
           
PPL Energy Supply         
Proceeds from sales of NDT securities (a) $ 139  $ 156  $ 114 
Other proceeds from sales   3       
Gross realized gains (b)   29    28    13 
Gross realized losses (b)   21    16    5 
The following table shows proceeds from and realized gains and losses on sales of available-for-sale securities.                   
 2015 2014 2013
Proceeds from sales of NDT securities (a)$180
 $154
 $144
Other proceeds from sales2
 9
 —
Gross realized gains (b)26
 23
 17
Gross realized losses (b)22
 10
 7

(a)These proceeds are used to pay income taxes and fees related to managing the trust.  Remaining proceeds are reinvested in the trust.
(b)Excludes the impact of other-than-temporary impairment charges recognized on the Statements of Income.

Short-term Investments(PPL, LKE and LG&E)

At December 31, 2010, LG&E held $163 million aggregate principal amount of tax-exempt revenue bonds issued by Louisville/Jefferson County, Kentucky on behalf of LG&E that were purchased from the remarketing agent in 2008.  In 2011, LG&E received $163 million for its investments in these bonds when they were remarketed to unaffiliated investors.  No realized or unrealized gains (losses) were recorded on these securities, as the difference between carrying value and fair value was not significant.

NDT Funds(PPL and PPL Energy Supply)

Amounts previously collected from PPL Electric's customers for decommissioning the Susquehanna nuclear plant, less applicable taxes, were deposited in external trust funds for investment and can only be used for future decommissioning costs. To the extent that the actual costs for decommissioning exceed the amounts in the nuclear decommissioning trust funds, PPL Susquehanna Nuclear would be obligated to fund 90% of the shortfall.


When
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20.  Accumulated Other Comprehensive Income (Loss)

The after-tax changes in Talen Energy's AOCI by component for the fair valueyears ended December 31 were as follows.         
 Unrealized gains (losses) Defined benefit plans  
 
Available-
for-sale
securities
 
Qualifying
derivatives
 
Prior
service
costs
 
Actuarial
gain
(loss)
 Total
December 31, 2012$112
 $211
 $(10) $(265) $48
Amounts arising during the period67
 —
 2
 71
 140
Reclassifications from AOCI(6) (123) 4
 14
 (111)
Net OCI during the period61
 (123) 6
 85
 29
December 31, 2013$173
 $88
 $(4) $(180) $77
          
Amounts arising during the period35
 —
 8
 (120) (77)
Reclassifications from AOCI(6) (25) 3
 5
 (23)
Net OCI during the period29
 (25) 11
 (115) (100)
December 31, 2014$202

$63

$7

$(295)
$(23)
          
Amounts arising during the period(6) —
 (3) 46
 37
Reclassifications from AOCI(2) (19) (1) (18) (40)
Net OCI during the period(8) (19) (4) 28
 (3)
December 31, 2015$194
 $44
 $3
 $(267) $(26)

The following table presents the gains (losses) and related income taxes for reclassifications from Talen Energy's AOCI for the years ended December 31.  The defined benefit plan components of a security is less than amortized cost, PPL and PPL Energy Supply must make certain assertions to avoid recording an other-than-temporary impairment that requires a current period charge to earnings.  The NRC requires that nuclear decommissioning trusts be managed by independent investment managers, with discretion to buy and sell securitiesAOCI are not reflected in their entirety in the trusts.  As a result, PPL and PPL Energy Supply have been unable to demonstratestatement of income during the ability to hold an impaired security until it recovers its value; therefore, unrealized losses on equity securities for all periods presented, represented other-than-temporary impairments that required a current period charge to earnings.  PPL and PPL Energy Supply recorded impairments for certain securities investedyears; rather, they are included in the NDT fundscomputation of $1 million, $6 million and $3 millionnet periodic defined benefit costs (credits).  See Note 9 for 2012, 2011 and 2010.  These impairments are reflected on the Statements of Income in "Other-Than-Temporary Impairments."additional information.     
      Affected Line Item on the
Details about AOCI 2015 2014 Statements of Income
Available-for-sale securities $4
 $13
 Other Income (Expense) - net
Income Taxes (2) (7)  
Total After-tax 2
 6
  
       
Qualifying derivatives      
Commodity contracts (3) 1
 Wholesale energy
  33
 31
 Energy purchases
  —
 8
 Discontinued operations
  1
 2
 Other
Total Pre-tax 31
 42
  
Income Taxes (12) (17)  
Total After-tax 19
 25
  
       
Defined benefit plans      
Prior service costs 1
 (4)  
Net actuarial loss 29
 (9)  
Total Pre-tax 30
 (13)  
Income Taxes (11) 5
  
Total After-tax 19
 (8)  
Total reclassifications during the period $40
 $23
  


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24.21.  New Accounting Guidance Pending Adoption

(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)Accounting for Revenue from Contracts with Customers

Improving Disclosures about Offsetting Balance Sheet Items

Effective January 1, 2013,In May 2014, the Registrants will retrospectively adopt accounting guidanceFASB issued to enhance disclosures about derivative instruments that either (1) offset on the balance sheet or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the balance sheet.

Upon adoption, the enhanced disclosure requirements are not expected to have a significant impact on the Registrants.
390
Testing Indefinite-Lived Intangible Assets for Impairment

Effective January 1, 2013, the Registrants will prospectively adopt accounting guidance that allows an entity to electestablishes a comprehensive new model for the option to first make a qualitative evaluation about the likelihoodrecognition of an impairment of an indefinite-lived intangible asset.  If,revenue from contracts with customers.  This model is based on this assessment,the core principle that revenue should be recognized to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity determinesexpects to be entitled in exchange for those goods or services.

This guidance can be applied using either a full retrospective or modified retrospective transition method. In August 2015, the FASB issued guidance that defers the effective date of the standard by one year, which for public business entities, results in initial application of this guidance in annual reporting periods beginning after December 15, 2017 and interim periods within those years. Entities may early adopt the guidance as of the original effective date of the standard, which for public business entities is annual reporting periods beginning after December 15, 2016. Talen Energy expects to adopt this guidance effective January 1, 2018.

Talen Energy is currently assessing the impact of adopting this guidance, as well as the transition method it will use.

Reporting Uncertainties about an Entity's Ability to Continue as a Going Concern

In August 2014, the FASB issued accounting guidance which will require management to assess, for each interim and annual period, whether there are conditions or events that raise substantial doubt about an entity's ability to continue as a going concern.  Substantial doubt about an entity's ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is more likely than notprobable that the fair valueentity will be unable to meet its obligations as they become due within one year after the date the financial statements are issued.

When management identifies conditions or events that raise substantial doubt about an entity's ability to continue as a going concern, management is required to disclose information that enables users of the indefinite-lived intangible asset exceedsfinancial statements to understand the carrying amount,principal conditions or events that raised substantial doubt about the fair valueentity's ability to continue as a going concern and management's evaluation of the significance of those conditions or events.  If substantial doubt about the entity's ability to continue as a going concern has been alleviated as a result of management's plan, the entity should disclose information that asset does not needallows the users of the financial statements to be calculated.understand those plans.  If the entity concludes otherwise,substantial doubt about the entity's ability to continue as a quantitative impairment test mustgoing concern is not alleviated by management's plans, management's plans to mitigate the conditions or events that gave rise to the substantial doubt about the entity's ability to continue as a going concern should be performed by determiningdisclosed, as well as a statement that there is substantial doubt the fair value ofentity's ability to continue as a going concern within one year after the asset and comparing it withdate the carrying value.  The entity would record an impairment charge, if necessary.financial statements are issued.

UponFor all entities, this guidance should be applied prospectively within the annual periods ending after December 15, 2016, and for annual periods and interim periods thereafter.  Early adoption is permitted.

Talen Energy will adopt this guidance for the annual period ending December 31, 2016. The adoption of this guidance is not expected to have a significant impact onimpact. 
Determining Whether the Registrants.Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity

Reporting Amounts Reclassified OutIn November 2014, the FASB issued guidance that clarifies how current accounting guidance should be interpreted when evaluating the economic characteristics and risks of AOCIa host contract of a hybrid financial instrument issued in the form of a share.  This guidance does not change the current criteria for determining whether separation of an embedded derivative feature from a hybrid financial instrument is required.  Entities are still required to evaluate whether the economic risks of the embedded derivative feature are clearly and closely related to those of the host contract, among other relevant criteria.

EffectiveAn entity should consider the substantive terms and features of the entire hybrid financial instrument, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract to determine whether the host contract is more akin to a debt instrument or more akin to an equity instrument.  An entity should assess the relative strength of the debt-like and equity-like terms and features when determining how to weight those terms and features.

For public business entities, this guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and should be applied using a modified retrospective method for existing hybrid financial instruments

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issued in the form of a share as of the beginning of the fiscal year the guidance is adopted.  Early adoption is permitted.  Retrospective application is permitted but not required.

Talen Energy will adopt this guidance effective January 1, 2013, the Registrants will prospectively adopt accounting2016.  The adoption of this guidance issued to improve the reporting of reclassifications out of AOCI.  The Registrants will be required to provide information about the effects on net income of significant amounts reclassified out of AOCI by their respective statement of income line item, if the item is required to be reclassified to net income in its entirety.  For items not reclassified to net income in their entirety, the Registrants will be required to reference other disclosures that provide details on these amounts.

Upon adoption, the enhanced disclosure requirements are not expected to have a significant impactimpact.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued accounting guidance to simplify the presentation of debt issuance costs by requiring debt issuance costs to be presented on the Registrants.
391

SCHEDULE I - LG&E and KU Energy LLC
CONDENSED UNCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars)       
                 
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
              
Operating Revenues
             
              
Operating Expenses             
 
Other operation and maintenance
 $ 3         $ (3)
 
Total Operating Expenses
   3          (3)
                 
Operating Income (Loss)
   (3)          3 
                 
Equity in Earnings of Subsidiaries
   234  $ 267  $ 48     204 
                 
Other Income (Expense) - net
             (1)
              
Interest Income with Affiliate
   10    29    5     29 
                 
Interest Expense
   39    31    4     
                 
Interest Expense with Affiliate
   2    2    1     47 
                 
Income (Loss) Before Income Taxes
   200    263    48     188 
                 
Income Tax Expense (Benefit)
   (19)   (2)   1     (2)
                 
Net Income (Loss) Attributable to Member
 $ 219  $ 265  $ 47   $ 190 
                 
Comprehensive Income (Loss) Attributable to Member
 $ 200  $ 263  $ 53   $ 180 
                 
The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
392
SCHEDULE I - LG&E and KU Energy LLC
CONDENSED UNCONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)       
                 
     Successor  Predecessor
         Two Months  Ten Months
     Year Ended Year Ended Ended  Ended
     December 31, December 31, December 31,  October 31,
     2012  2011  2010   2010 
              
Cash Flows from Operating Activities             
Net cash provided by (used in) operating activities
 $ 364  $ 346  $ 53   $ 156 
              
Cash Flows from Investing Activities             
  
Capital contributions to affiliated subsidiaries
         (3)    (525)
  
Net decrease (increase) in notes receivable from affiliates
   (15)   (63)   313     234 
Net cash provided by (used in) investing activities
   (15)   (63)   310     (291)
                 
Cash Flows from Financing Activities             
  
Net increase (decrease) in debt with affiliates
         (208)    243 
  Net (decrease) increase in notes payable with affiliates  (196)          
  
Repayment of short-term borrowings
         (2,103)    
  
Retirement of long-term debt
         (400)    
  
Issuance of long-term debt
      250    870     
  
Debt-issuance costs
         (6)    
  
Contribution from member
         1,565     
  
Distribution to member
   (155)   (533)   (100)    
  
Payment of common stock dividends
             (87)
Net cash provided by (used in) financing activities
   (351)   (283)   (382)    156 
                 
Net Increase (Decrease) in Cash and Cash Equivalents   (2)      (19)    21 
Cash and Cash Equivalents at Beginning of Period
   2    2    21     
Cash and Cash Equivalents at End of Period
 $  $ 2  $ 2   $ 21 
                 
                 
Supplemental disclosures of cash flow information:             
Cash Dividends Received from Affiliated Subsidiaries
 $ 175  $ 207  $   $ 105 
                 
The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
393
balance sheet as a direct deduction from the carrying amount of the associated debt liability, consistent with the presentation of debt discounts. Because this guidance did not address the treatment of debt issuance costs related to line-of-credit arrangements, additional guidance was issued in August 2015 stating that an entity may defer and amortize debt issuance costs over the term of a line-of-credit arrangement, regardless of whether there are any related outstanding borrowings.

SCHEDULE I - LG&E and KU Energy LLC
CONDENSED UNCONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
(Millions of Dollars)
          
     2012  2011 
Assets      
          
Current Assets      
 
Cash and cash equivalents
    $ 2 
 
Accounts receivable from affiliates
 $ 4    11 
 
Notes receivable from affiliates
   1,560    1,520 
 
Other current assets
   1    4 
 
Total Current Assets
   1,565    1,537 
          
Investments      
 
Affiliated companies at equity
   4,096    4,056 
          
Other Noncurrent Assets      
 
Deferred income taxes
   184    163 
 
Other noncurrent assets
   7    8 
 
Total Other Noncurrent Assets
   191    171 
          
Total Assets
 $ 5,852  $ 5,764 
          
Liabilities and Equity      
          
Current Liabilities      
 
Notes payable to affiliates
 $ 25    
 
Accounts payable to affiliates
   906  $ 701 
 
Taxes
   8    
 
Other current liabilities
   6    6 
 
Total Current Liabilities
   945    707 
          
Long-term Debt      
 
Long-term debt
   1,121    1,120 
 
Notes payable to affiliates
      196 
 
Total Long-term Debt
   1,121    1,316 
       
Equity
   3,786    3,741 
          
Total Liabilities and Equity
 $ 5,852  $ 5,764 
          
The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
For public business entities, this guidance should be applied retrospectively for financial statements issued for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. Early adoption is permitted.

Talen Energy will adopt this guidance effective January 1, 2016. The adoption of this guidance will require Talen Energy to reclassify debt issuance costs from assets to long-term debt, and is not expected to have a significant impact.
 
Recognition of Measurement of Financial Assets and Financial Liabilities
394
In January 2016, the FASB issued accounting guidance that affects the accounting for equity investments, financial liabilities under the fair value option, and the disclosure requirements for financial instruments. This guidance generally requires entities to measure equity investments that are not accounted for under the equity method of accounting and do not result in consolidation at fair value and recognize any changes in fair value in net income. Entities may elect to record equity investments without readily determinable fair values at cost, less impairment, adjusted for observable price changes. The impairment model for equity investments subject to this election is a single-step qualitative assessment performed each quarter. For financial liabilities measured using the fair value option, changes in fair value related to instrument-specific credit risk to be presented separately within OCI.

For public business entities, this guidance should generally be applied prospectively for financial statements issued for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is generally not permitted, although entities may early adopt the provision related to financial liabilities under the fair value option.

Talen Energy expects to adopt this guidance effective January 1, 2018. Upon adoption, an entity will record a cumulative-effect adjustment to beginning retained earnings as of the beginning of the first reporting period in which the guidance is adopted, with the exception that the amendments related to equity securities with readily determined fair values should be applied prospectively. Talen Energy is currently assessing the impact of adopting this guidance, which may be significant for equity securities held in the NDT funds.

Accounting for Leases

In February 2016, the FASB issued accounting guidance that updates the accounting for leases.  The updated guidance will require lessees to recognize assets and liabilities for the rights and obligations created by their leases with lease terms of more than 12 months.  Consistent with current accounting guidance, the recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee primarily will depend on its classification as a finance (similar to the current capital lease) or an operating lease.  However, unlike current accounting guidance, which requires only capital leases to be recognized on the balance sheet, the new accounting guidance will require both types of leases to be recognized on the balance sheet.

The new accounting guidance also will require disclosures to help investors and other financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases. These disclosures include qualitative and quantitative requirements, providing additional information about the amounts recorded in the financial statements.

The accounting by lessors will remain largely unchanged.  However, the new accounting guidance contains some targeted improvements that are intended to align, where necessary, lessor accounting with the lessee accounting model and with the updated revenue recognition guidance issued in 2014 and discussed above.


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For public business entities, this guidance is effective for annual reporting periods beginning after December 15, 2018 and interim periods within those years.  Early application is permitted.  In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach.  The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply.  These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date, and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset.  An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous accounting guidance unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous accounting guidance.

Talen Energy is currently assessing the impact of adopting this guidance and expects to adopt this guidance effective January 1, 2019.


   

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SCHEDULE I - LG&E and KU Energy LLCTALEN ENERGY CORPORATION
CONDENSED UNCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Millions of Dollars, except share data)  
 Year Ended December 31, 2015 (a) Inception through December 31, 2014 (a)
Operating Revenues$—
 $—
Operating Expenses—
 —
Operating Income (Loss)—
 —
Other Income (Expense) - net   
Equity in earnings of subsidiaries(373) —
Total Other Income (Expense) - net(373) —
Net Income (Loss) Attributable to Talen Energy Corporation Stockholders$(373) $—
Comprehensive Income (Loss) Attributable to Talen Energy Corporation Stockholders$(449) $—
Earnings Per Share of Common Stock:   
Net Income (Loss) Available to Talen Energy Corporation Common Stockholders   
Basic$(2.90) $—
Diluted$(2.90) $—
Weighted-Average Shares of Common Stock Outstanding (in thousands) (b)   
Basic128,509
 —
Diluted128,509
 —

(a)Talen Energy Corporation was incorporated in June 2014 and its business operations began in June 2015 after the completion of its spinoff from PPL. Therefore, the 2015 results are primarily from June 1 to December 31, while the 2014 results are from the same period. See Note 1 to the Unconsolidated Financial Statements for additional information.
(b)Weighted average shares were calculated for the seven month period from June 1, 2015 to December 31, 2015.

The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.


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SCHEDULE I - TALEN ENERGY CORPORATION
CONDENSED UNCONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31, 2015 (a)Inception through December 31, 2014 (a)
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities$—
$—
Cash Flows from Investing Activities
Net cash provided by (used in) investing activities—
—
Cash Flows from Financing Activities
Net cash provided by (used in) financing activities—
—
Net Increase (Decrease) in Cash and Cash Equivalents—
—
Cash and Cash Equivalents at Beginning of Period—
—
Cash and Cash Equivalents at End of Period$—
$—

(a)Talen Energy Corporation was incorporated in June 2014 and its business operations began in June 2015 after the completion of its spinoff from PPL. Therefore, the 2015 results are primarily from June 1 to December 31, while the 2014 results are from the same period. See Note 1 to the Unconsolidated Financial Statements for additional information.


The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.


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SCHEDULE I - TALEN ENERGY CORPORATION   
CONDENSED UNCONSOLIDATED BALANCE SHEETS AT DECEMBER 31,
(Millions of Dollars, shares in thousands)  
 2015 2014
Assets   
Investments   
Affiliated companies at equity$4,303
 $—
    
Total Assets$4,303
 $—
    
Liabilities and Equity   
Equity   
Common stock - $0.001 par value (a)$—
 $—
Additional paid-in capital4,702
 —
Accumulated deficit(373) —
Accumulated other comprehensive loss(26) —
Total Equity4,303
 —
Total Liabilities and Equity$4,303
 $—

(a) 1,000,000 shares authorized; 128,509 shares issued and outstanding at December 31, 2015.

The accompanying Notes to Condensed Unconsolidated Financial Statements are an integral part of the financial statements.


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SCHEDULE I - TALEN ENERGY CORPORATION
NOTES TO CONDENSED UNCONSOLIDATED FINANCIAL STATEMENTS

1.Basis of Presentation

LG&EIn June 2014, Talen Energy Corporation was incorporated in connection with PPL and KUTalen Energy LLC (LKE) isSupply executing definitive agreements with the Riverstone Holders to combine their competitive power generation businesses into a holdingnew, stand-alone, publicly traded company named Talen Energy Corporation. On June 1, 2015, PPL completed the spinoff to PPL shareowners of a newly formed entity, Talen Energy Holdings, Inc. (Holdco), which at such time owned all of the membership interests of Talen Energy Supply and all of the common stock of Talen Energy Corporation. Immediately following the spinoff, Holdco merged with a special purpose subsidiary of Talen Energy Corporation, with Holdco continuing as the surviving company to the merger and as a wholly owned subsidiary of Talen Energy Corporation and the sole owner of Talen Energy Supply. As a result, the operating results reflected on the Statement of Income represent activity that occurred after June 1, 2015. Talen Energy Corporation conducts substantially all of its business operations through its subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are largely dependent upon the earnings of these subsidiaries and the distribution or other payment of such earnings to it in the form of dividends or repayment of loans and advances from the subsidiaries.  These condensed unconsolidated financial statements and related footnotes have been prepared in accordance with Reg.Reg §210.12-04 of Regulation S-X. On an unconsolidated basis, there is no comparable information for Talen Energy Corporation prior to the June 1, 2015 spinoff from PPL. These statements should be read in conjunction with the consolidated financial statements and notes thereto of LKE.Talen Energy Corporation.

LKETalen Energy Corporation indirectly or directly owns all of the ownership interests of its significant subsidiaries. LKE relies primarilySee Note 5 to Talen Energy Corporation's consolidated financial statements for discussions on dividends fromrestricted net assets of its subsidiaries for the purpose of transferring funds to fund LKE's dividends to its member and to meet its other cash requirements.Talen Energy Corporation in the form of distributions, loans or advances.

2.Commitments and Contingencies

See Note 1511 to LKE'sTalen Energy Corporation's consolidated financial statements for commitments and contingencies of its subsidiaries.

Guarantees and Other Assurances

LKE provides certain indemnifications,Talen Energy Corporation's subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts that may become due under Talen Energy Corporation's guarantees or other assurances or to make any funds available for such payment.

In the most significantnormal course of which relatebusiness, Talen Energy Corporation enters into agreements that provide financial assurance to the termination of the WKE lease in July 2009.  See Note 9 to LKE's consolidated financial statements for additional information.  These guarantees cover the due and punctual payment, performance and discharge by each party of its respective present and future obligations.  The most comprehensive of these guarantees is the LKE guarantee covering operational, regulatory and environmental commitments and indemnifications made by WKE under the WKE Transaction Termination Agreement.  This guarantee has a term of 12 years ending July 2021, and a cumulative maximum exposure of $200 million.  Certain items such as government fines and penalties fall outside the cumulative cap.  LKE has contested the applicability of the indemnification requirement relating to one matter presented by a counterparty under this guarantee.  Another guarantee with a maximum exposure of $100 million covering other indemnifications expires in 2023.  In May 2012, LKE's indemnitee received an arbitration panel's decision affecting this matter, which granted LKE's indemnitee certain rights of first refusal to purchase excess power at a market-based price rather than at an absolute fixed price.  In January 2013, LKE's indemnitee commenced a proceeding in the Kentucky Court of Appeals appealing a December 2012 order of the Henderson Circuit Court confirming the arbitration award.  LKE believes its indemnification obligations in this matter remain subject to various uncertainties, including the potential for additional legal challenges regarding the arbitration decision as well as future prices, availability and demand for the subject excess power.  LKE continues to evaluate various legal and commercial options with respect to this indemnification matter.  The ultimate outcomes of the WKE termination-related indemnifications cannot be predicted at this time.  Additionally, LKE has indemnified various third parties relatedon behalf of certain subsidiaries. Such agreements include surety bonds issued by insurance companies. These agreements are entered into primarily to historical obligations for other divestedsupport or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or to facilitate the commercial activities in which these subsidiaries and affiliates.  The indemnifications vary by entity and the maximum exposures range from being capped at the sale price to no specified maximum; however, LKE is not aware of formal claims under such indemnities made by any party at this time.  LKE could be required to perform on these indemnifications in the event of covered losses or liabilities being claimed by an indemnified party.  In the second quarter of 2012, LKE adjusted its investments in subsidiaries for certain of these indemnifications by $9 million ($5 million after-tax), which is reflected in "Equity in Earnings of Subsidiaries" on the Statement of Income.  LKE cannot predict the ultimate outcomes of such indemnification circumstances, but does not currently expect such outcomes to result in significant losses above the amounts recorded.
395
QUARTERLY FINANCIAL, COMMON STOCK PRICE AND DIVIDEND DATA (Unaudited)
PPL Corporation and Subsidiaries
(Millions of Dollars, except per share data)
    For the Quarters Ended (a)
    March 31 June 30 Sept. 30 Dec. 31
2012             
Operating revenues
 $ 4,112  $ 2,549  $ 2,403  $ 3,222 
Operating income
   1,051    572    664    822 
Income from continuing operations after income taxes
   545    277    355    360 
Income (loss) from discontinued operations
      (6)      
Net income
   545    271    355    360 
Net income attributable to PPL
   541    271    355    359 
Income from continuing operations after income taxes available to            
 PPL common shareowners: (b)            
  
Basic EPS
   0.93    0.47    0.61    0.61 
  
Diluted EPS
   0.93    0.47    0.61    0.60 
Net income available to PPL common shareowners: (b)            
  
Basic EPS
   0.93    0.46    0.61    0.61 
  
Diluted EPS
   0.93    0.46    0.61    0.60 
Dividends declared per share of common stock (c)
   0.360    0.360    0.360    0.360 
Price per common share:            
  
High
 $ 29.85  $ 28.44  $ 29.98  $ 30.18 
  
Low
   27.29    26.68    27.72    27.74 
               
2011             
Operating revenues
 $ 2,910  $ 2,489  $ 3,120  $ 4,218 
Operating income
   805    595    767    934 
Income from continuing operations after income taxes
   402    201    449    458 
Income (loss) from discontinued operations
   3    (1)      
Net income
   405    200    449    458 
Net income attributable to PPL
   401    196    444    454 
Income from continuing operations after income taxes available to            
 PPL common shareowners: (b)            
  
Basic EPS
   0.82    0.35    0.76    0.78 
  
Diluted EPS
   0.82    0.35    0.76    0.78 
Net income available to PPL common shareowners: (b)            
  
Basic EPS
   0.82    0.35    0.76    0.78 
  
Diluted EPS
   0.82    0.35    0.76    0.78 
Dividends declared per share of common stock (c)
   0.350    0.350    0.350    0.350 
Price per common share:            
  
High
 $ 26.98  $ 28.38  $ 29.61  $ 30.27 
  
Low
   24.10    25.23    25.00    27.00 
engage.


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QUARTERLY FINANCIAL DATA (UNAUDITED)
Talen Energy Corporation and Subsidiaries
(Millions of Dollars, except per share data)
  For the 2015 Quarters Ended (a) For the 2014 Quarters Ended (a)
  Mar. 31 June 30 Sept. 30 Dec. 31 Mar. 31 June 30 Sept. 30 Dec. 31
Operating revenues as previously reported $946
 $1,065
 $1,419
 
 $(955) $1,007
 $1,601
 $2,083
Reclassification between revenue and expense (b) 145
 (125) (135)   1,901
 83
 (409) (730)
Reclassification from discontinued operations (c) —
 8
 36
   —
 —
 —
 —
Operating revenues 1,091

948
 1,320

$1,122

946

1,090

1,192

1,353
Operating Income (Loss) as previously reported 
 34
 (246) 
        
Reclassification from discontinued operations (c)   1
 (100)          
Operating Income (Loss) 178
 35
 (346) 94
 (79) 16
 189
 271
Income (Loss) from continuing operations after income taxes as previously reported 
 25
 (339) 
        
Reclassification from discontinued operations (c)   1
 (62)          
Income (Loss) from continuing operations after income taxes 96
 26
 (401) (62) (58) 2
 94
 149
Income (Loss) from discontinued operations as previously reported 
 1
 (62) 
        
Reclassification from discontinued operations (c)   (1) 62
          
Income (Loss) from discontinued operations —
 —
 —
 —
 (8) 11
 7
 213
Net Income (Loss) Attributable to Talen Energy Corporation stockholders (d) 96
 26
 (401) (62) (66) 13
 101
 362
                 
Income (Loss) from continuing operations after income taxes available to Talen Energy Corporation stockholders (e)                
Basic EPS 1.15
 0.26
 (3.12) (0.48) (0.69) 0.03
 1.13
 1.78
Diluted EPS (f) 1.15
 0.26
 (3.12) (0.48) (0.69) 0.03
 1.13
 1.78
Net Income (Loss) available to Talen Energy Corporation stockholders (e)                
Basic EPS 1.15
 0.26
 (3.12) (0.48) (0.79) 0.16
 1.21
 4.33
Diluted EPS (f) 1.15
 0.26
 (3.12) (0.48) (0.79) 0.16
 1.21
 4.33
(a)Quarterly results can vary depending on, among other things, weather and the forward pricing of power. Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.
(b)In the fourth quarter of 2015, Talen Energy reclassified amounts between "Wholesale energy" within operating revenues and "Energy purchases" within operating expense on the Statements of Income. See Note 1 to the Financial Statements for additional information.
(c)In the fourth quarter of 2015, the Sapphire operations, which were originally classified as discontinued operations as part of the RJS Power acquisition, were reclassified to continuing operations. See Note 1 to the Financial Statements for additional information.
(d)The third and fourth quarters of 2015 include impairment charges related to goodwill, the Sapphire plants and the C.P. Crane plant. The fourth quarter of 2014 includes a gain of $137 million (after tax) from the sale of hydroelectric generating facilities of Talen Montana. See Note 6 to the Financial Statements for additional information on the sale and Notes 14 and 16 to the Financial Statements for additional information on the impairments.
(e)The sum of the quarterly amounts may not equal annual earnings per share due to changes in the number of common shares outstanding during the year or rounding.
(c)PPL has paid quarterly cash dividends on its common stock
(f)As a result of reported losses, weighted-average shares used in every year since 1946.  Future dividends, declared at the discretion ofdiluted earnings per share computations for the Board of Directors, will be dependent upon future earnings, cash flows, financial requirementsquarters ended September 30 and other factors.December 31, 2015 excludes incremental shares as they were anti-dilutive.

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396
QUARTERLY FINANCIAL DATA (Unaudited)
PPL Electric Utilities Corporation and Subsidiaries
(Millions of Dollars)
  For the Quarters Ended (a)
   March 31  June 30  Sept. 30  Dec. 31
2012             
Operating revenues
 $ 458  $ 404  $ 444  $ 457 
Operating income
   79    63    71    81 
Net income
   37    29    33    37 
Net income available to PPL
   33    29    33    37 
             
2011             
Operating revenues
 $ 558  $ 440  $ 455  $ 439 
Operating income
   103    82    69    94 
Net income
   56    40    32    61 
Net income available to PPL
   52    36    28    57 

(a)PPL Electric's business is seasonal in nature, with peak sales periods generally occurring in the winter and summer months.  Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.
397

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

PPLTalen Energy Corporation PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

None.

ITEM 9A. CONTROLS AND PROCEDURES
(a)Evaluation of disclosure controls and procedures.
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
The registrants' principal executive officers and principal financial officers, based on their evaluation of the registrants' disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of December 31, 2012, the registrants' disclosure controls and procedures are effective to ensure that material information relating to the registrants and their consolidated subsidiaries is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms, particularly during the period for which this annual report has been prepared.  The aforementioned principal officers have concluded that the disclosure controls and procedures are also effective to ensure that information required to be disclosed in reports filed under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, to allow for timely decisions regarding required disclosure.
(b)Changes in internal control over financial reporting.
PPL Corporation
The registrant's principal executive officer and principal financial officer have concluded that there were no changes in the registrant's internal control over financial reporting during the registrant's fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the registrant's internal control over financial reporting.
As reported in the 2011 Form 10-K, PPL's principal executive officer and principal financial officer concluded that a systems migration related to the WPD Midlands acquisition created a material change to its internal control over financial reporting in 2012.  In December 2011, the use of legacy information technology systems at WPD Midlands was discontinued and the related data, processes and internal controls were migrated to the systems, processes and controls currently in place at PPL WW.
Risks related to the systems migration were partially mitigated by PPL's expanded internal control over financial reporting that were implemented subsequent to the acquisition and PPL's existing policy of consolidating foreign subsidiaries on a one-month lag, which provided management additional time for review and analysis of WPD Midlands' results and their incorporation into PPL's consolidated financial statements.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
The registrants' principal executive officers and principal financial officers have concluded that there were no changes in the registrants' internal control over financial reporting during the registrants' fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.
Management's Report on Internal Control over Financial Reporting

398


PPL Corporation
PPL's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f).  PPL's internal control over financial reporting is a process designed to provide reasonable assurance to PPL's management and Board of Directors regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under the framework in "Internal Control - Integrated Framework," our management concluded that our internal control over financial reporting was effective as of December 31, 2012.  The effectiveness of our internal control over financial reporting has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report contained on page 197.
PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Management of PPL's non-accelerated filer companies, PPL Energy Supply, PPL Electric, LKE, LG&E and KU, are responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f).  Each of the aforementioned companies' internal control over financial reporting is a process designed to provide reasonable assurance to management and Board of Directors of these companies regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Under the supervision and with the participation of our management, including the principal executive officers and principal financial officers of the companies listed above, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on our evaluation under the framework in "Internal Control - Integrated Framework," management of these companies concluded that our internal control over financial reporting was effective as of December 31, 2012.  This annual report does not include an attestation report of Ernst & Young LLP, the companies' independent registered public accounting firm regarding internal control over financial reporting for these non-accelerated filer companies.  The effectiveness of internal control over financial reporting for the aforementioned companies was not subject to attestation by the companies' registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit these companies to provide only management's report in this annual report.
Item 9A. Controls and Procedures

ITEM 9B. OTHER INFORMATION
PPL Corporation, PPLTalen Energy Corporation and Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.

(a)    Evaluation of Disclosure Controls and Procedures.
The registrants' principal executive officers and principal financial officers, based on their evaluation of the registrants' disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) of the Securities Exchange Act of 1934) have concluded for their respective companies that, as of December 31, 2015, the registrants' disclosure controls and procedures were effective to ensure that information required to be disclosed by each registrant in the reports filed by it under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that such information is accumulated and communicated to management, including the principal executive and principal financial officers, to allow for timely decisions regarding required disclosure.

(b)    Change in Internal Controls over Financial Reporting.

The registrants' principal executive officers and principal financial officers have concluded for the fourth quarter for their respective companies that the June 1, 2015 RJS acquisition and the November 1, 2015 MACH Gen acquisition created material changes to its internal control over financial reporting. RJS collectively is a significant subsidiary, representing as of and for the year ended December 31, 2015 approximately 17% and 12% of Talen Energy's total consolidated assets and revenue. MACH Gen is a significant subsidiary, representing as of December 31, 2015 approximately 10% of Talen Energy's total consolidated assets. The registrants are transitioning the processes, information technology systems and other components of internal control over financial reporting of RJS Power and MACH Gen to the internal control structure of the registrants. The registrants have expanded their consolidation and disclosure controls and procedures related to the acquired companies, and the registrants continue to assess the current internal control over financial reporting at RJS and MACH Gen. Accordingly, as permitted under SEC guidance, each of the registrants has elected to exclude RJS and MACH Gen from its management's assessment of the effectiveness of internal controls as of December 31, 2015. Except for the RJS and MACH Gen acquisitions, the aforementioned principal executive officers and principal financial officers have concluded for their respective companies that there were no other changes in the registrants' internal control over financial reporting during the registrants' fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Management of each of the registrants is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) or 15d-15(f). Internal control over financial reporting for each registrant is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

The management of each registrant, with the participation of their respective principal executive officer and principal financial officer, conducted an evaluation of the effectiveness of its internal control over financial reporting as of the end of the fiscal year based on the framework in "Internal Control - Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on their evaluation under the framework in "Internal Control - Integrated Framework" (2013), the management of each of the registrants concluded for their respective companies that each registrant's internal control over financial reporting was effective as of December 31, 2015.

As permitted by SEC guidance and for the reasons set forth under "Change in Internal Controls over Financial Reporting" above each of the registrants has elected to exclude RJS and MACH Gen from management's assessment of internal controls as of December 31, 2015. RJS collectively is a significant subsidiary, representing as of and for the year ended December 31, 2015 approximately 17% and 12% of Talen Energy's total consolidated assets and revenue. The RJS entities were acquired in

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399

June 2015. MACH Gen is a significant subsidiary, representing as of December 31, 2015 approximately 10% of Talen Energy's total consolidated assets. MACH Gen and its subsidiaries were acquired in November 2015.

With respect to Talen Energy Corporation, this annual report does not include an attestation report of Ernst & Young LLP, its independent registered public accounting firm, regarding effectiveness of internal control over financial reporting due to a transition period established by the SEC for newly public companies.

With respect to Talen Energy Supply, this annual report does not include an attestation report of Ernst & Young LLP, its independent registered public accounting firm, regarding effectiveness of internal control over financial reporting based upon rules of the SEC that permit a non-accelerated filer to provide only management's report on internal control over financial reporting in its annual report.

ITEM 9B. OTHER INFORMATION

Talen Energy Corporation and Talen Energy Supply, LLC

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

PPLTalen Energy Corporation

Additional information forrequired by this item will be set forth inincluded under the sections entitled "Nominees forcaptions "Proposals - Proposal 1: Election of Directors," "Board"Corporate Governance - Board Committees - Compensation, Governance and Nominating Committee - Governance and Director Nominations," "Security Ownership of Certain Beneficial Owners and Management - Section 16(a) Beneficial Ownership Reporting Compliance," "Corporate Governance - The Board - Code of Ethics," and "Corporate Governance - Board Committees - Audit Committee" and "Section 16(a) Beneficial Ownership Reporting Compliance" in PPL's 2013 Notice ofTalen Energy Corporation's Proxy Statement related to the 2016 Annual Meeting and Proxy Statement,of Stockholders, which will be filed with the SEC not later than 120 days after December 31, 2012,2015, and which information is incorporated herein by reference.  There have been no changes to the procedures by which shareowners may recommend nominees to PPL's board of directors since the filing with the SEC of PPL's 2012 Notice of Annual Meeting and Proxy Statement.  Information required by this item concerning the executive officers of PPL is set forth at the end of Part I of this report.

PPL has adopted a code of ethics entitled "Standards of Integrity" that applies to all directors, managers, trustees, officers (including the principal executive officers, principal financial officers and principal accounting officers (each, a "principal officer")), employees and agents of PPL and PPL's subsidiaries for which it has operating control (including PPLTalen Energy Supply, PPL Electric, LKE, LG&E and KU).  The "Standards of Integrity" are posted on PPL's Internet website: www.pplweb.com/about-us/corporate-governance.  A description of any amendment to the "Standards of Integrity" (other than a technical, administrative or other non-substantive amendment) will be posted on PPL's Internet website within four business days following the date of the amendment.  In addition, if a waiver constituting a material departure from a provision of the "Standards of Integrity" is granted to one of the principal officers, a description of the nature of the waiver, the name of the person to whom the waiver was granted and the date of the waiver will be posted on PPL's Internet website within four business days following the date of the waiver.

PPL also has adopted its "Guidelines for Corporate Governance," which address, among other things, director qualification standards and director and board committee responsibilities.  These guidelines, and the charters of each of the committees of PPL's board of directors, are posted on PPL's Internet website: www.pplweb.com/about-us/corporate-governance.

PPL Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Item 10 is omitted as PPLTalen Energy Supply PPL Electric, LKE, LG&E and KU meetmeets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K10-K.


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EXECUTIVE OFFICERS OF THE REGISTRANTSTALEN ENERGY

OfficersExecutive officers of the RegistrantsTalen Energy Corporation are elected annually by their Boardsits board of Directors (or Boarddirectors. The officers of ManagersTalen Energy Corporation are the same for PPLTalen Energy Supply) to serve at the pleasureSupply. Each holds office for a term of the respective Boards.  There are no family relationships among any of the executive officers, norone year until his successor is there any arrangementduly elected and qualified, or understanding between any executive officer and any other person pursuant to which the officer was selected.until his earlier death, resignation or removal.

There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.

Listed below are the executive officers of Talen Energy Corporation at December 31, 2012.2015.

PPL Corporation
Name Age Positions Held During the Past Five YearsDates
William H. Spence (a)55Chairman, President and Chief Executive OfficerApril 2012 - present
President and Chief Executive OfficerNovember 2011 - March 2012
President and Chief Operating OfficerJuly 2011 - November 2011
Executive Vice President and Chief Operating OfficerJune 2006 - July 2011
Position
Paul A. Farr 4548 Executive ViceDirector, President and Chief FinancialExecutive Officer
Jeremy R. McGuire April 2007 - present
Senior Vice President-FinancialJanuary 2006 - March 2007
Robert J. Grey (b)62Executive Vice President, General Counsel and SecretaryNovember 2012 - present
44 Senior Vice President, General CounselChief Financial Officer and SecretaryChief Accounting Officer
Clarence J. Hopf March 1996 - November 2012
David G. DeCampli (c) (f)55President-PPL Energy SupplyMarch 2012 - present
President-PPL ElectricApril 2007 - March 2012
Gregory N. Dudkin (d) (f)55President-PPL ElectricMarch 2012 - present
Senior Vice President-Operations-PPL ElectricJune 2009 - March 2012
Independent ConsultantFebruary 2009 - June 2009
Senior Vice-President of Technical Operations andJune 2006 - January 2009
 Fulfillment-Comcast Corporation
Robert D. Gabbard (f)53President-PPL EnergyPlusJune 2008 - present
Senior Vice President-Trading-PPL EnergyPlusJune 2008 - June 2008
59 Senior Vice President Merchant Trading Operations-Conectiv Energyand Chief Commercial Officer
Timothy S. Rausch 
June 2005 - May 2008
51 
Rick L. Klingensmith (f)52President-PPL GlobalAugust 2004 - present
Victor A. Staffieri (f)
57
Chairman of the Board,Senior Vice President and Chief Executive
Officer-LKE
Nuclear Officer
James E. Schinski 
May 2001 - present
56 
Mark F. Wilten (e)45Vice President-Finance and TreasurerJune 2012 - present
Treasurer-Nissan North America and Nissan MotorAugust 2010 - May 2012
 Acceptance Corporation
Assistant Treasurer-Nissan Motor Acceptance CorporationAugust 2008 - August 2010
Group Treasurer-Kensington Group plcOctober 2004 - January 2008
Vincent Sorgi41Senior Vice President and ControllerChief Administrative Officer
Paul M. Breme March 2010 - present
44 Controller-Supply AccountingJune 2008 - March 2010
Controller-PPL EnergyPlusApril 2007 - June 2008
(a)On April 1, 2012, William H. Spence was elected Chairman, President and Chief Executive Officer.
(b)On November 1, 2012, Robert J. Grey was elected Executive Vice President, General Counsel and Secretary.
(c)On March 4, 2012, David G. DeCampli resigned as President of PPL Electric.  On March 5, 2012, Mr. DeCampli was elected as
President of PPL Energy Supply.
(d)On March 4, 2012, Gregory N. Dudkin resigned as Senior Vice President-Operations of PPL Electric.  On March 5, 2012, Mr.
Dudkin was elected as President of PPL Electric.
(e)On June 4, 2012, Mark F. Wilten was elected Vice President-Finance and Treasurer.
(f)Designated an executive officer of PPL by virtue of their respective positions at a PPL subsidiary.Corporate Secretary
401

Paul A. Farr has served as Director, President and Chief Executive Officer since June 2015. He served as president of PPL Energy Supply, LLC (currently known as Talen Energy Supply, LLC) and PPL Generation, LLC (currently known as Talen Energy Generation, LLC) from June 2014 until June 2015. He also previously served as executive vice president and chief financial officer of PPL Corporation from April 2007 until June 2014.

Jeremy R. McGuire has served as Senior Vice President and Chief Financial Officer since June 2015. In August 2015, Mr. McGuire assumed the role of acting Chief Accounting Officer. Mr. McGuire, a former investment banker, joined PPL Corporation in 2008 and led the strategic planning function at that company from 2008 until June 2015.

Clarence J. Hopf, Jr. has served as Senior Vice President and Chief Commercial Officer since June 2015. He served as senior vice president - Fossil and Hydro Generation for PPL Energy Supply, LLC (currently known as Talen Energy Supply, LLC) from August 2014 until June 2015. Mr. Hopf joined PPL Corporation in October 2005 but left in 2008 to accept a position with Public Service Enterprise Group Incorporated (PSEG) as president of its energy marketing and trading subsidiary. He rejoined PPL EnergyPlus, LLC (currently known as Talen Energy Marketing, LLC) in 2012 and directed coal trading and supply, and later the wholesale marketing function, before being named eastern trading vice president in March 2014.

Timothy S. Rausch has served as Senior Vice President and Chief Nuclear Officer since June 2015. He served as senior vice president and chief nuclear officer of PPL Generation, LLC (currently known as Talen Generation, LLC) with responsibility for the Susquehanna nuclear plant, from July 2009 until June 2015.

James E. Schinski has served as Senior Vice President and Chief Administrative Officer since June 2015. He joined PPL Services in 2009 as vice president-chief information officer and served in that role until July 2014. From July 2014 until June 2015 he served in a vice president role to assist Talen Energy senior management in the transition from PPL Corporation to Talen Energy.

Paul M. Breme has served as Vice President, General Counsel and Corporate Secretary since June 2015. He joined PPL Corporation's Office of General Counsel in 2008 from the law firm of Cahill, Gordon & Reindel LLP, where he specialized in corporate law and finance. At PPL Corporation, he served as counsel from 2008 to 2009, as senior counsel until 2012 and as associate general counsel from 2012 until June 2015.


144

Table of Contents

ITEM 11. EXECUTIVE COMPENSATION

PPLTalen Energy Corporation

Information for this item will be set forth in the sections entitled "Compensation of Directors,"Corporate Governance - Board Compensation," "Compensation"Corporate Governance - Board Committees - Compensation, Governance and Nominating Committee - Compensation Committee Interlocks and Insider Participation" and "Executive Compensation" in PPL's 2013 Notice ofTalen Energy Corporation's Proxy Statement related to the 2016 Annual Meeting and Proxy Statement,of Stockholders, which will be filed with the SEC not later than 120 days after December 31, 2012,2015, and which information is incorporated herein by reference.

PPLTalen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Item 11 is omitted as PPLTalen Energy Supply PPL Electric, LKE, LG&E and KU meetmeets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

PPLTalen Energy Corporation

Information for this item will be set forth in the section entitled "Stock Ownership""Security Ownership of Certain Beneficial Owners and Management - Principal Stockholders" in PPL's 2013 Notice ofTalen Energy Corporation's Proxy Statement in connection with its 2016 Annual Meeting and Proxy Statement,of Stockholders, which will be filed with the SEC not later than 120 days after December 31, 2012,2015, and which information is incorporated herein by reference. In addition, provided below in tabular format is information as of December 31, 2012,2015, with respect to compensation plans (including individual compensation arrangements) under which equity securities of PPLTalen Energy Corporation are authorized for issuance.

Equity Compensation Plan Information
Equity Compensation Plan Information
       
 Number of securities to be  Number of securities
 issued upon exercise ofWeighted-average exerciseremaining available for future
 outstanding options, warrantsprice of outstanding options,issuance under equity
 
and rights (3)
warrants and rights (3)
compensation plans (4)
Equity compensation     334,877 - ICP
plans approved by 4,968,849 - ICP$ 30.72- ICP 5,688,059 - ICPKE
security holders (1) 413,210 - SIP$ 28.19- SIP 9,541,170 - SIP
  3,752,486 - ICPKE$ 30.12- ICPKE 1,948,928 - DDCP
  9,134,545 - Total$ 30.36- Combined 17,513,034 - Total
       
Equity compensation      
plans not approved by      
security holders (2)      
Plan CategoryNumber of securities to be issued upon exercise of outstanding options, warrants and rightsWeighted-average exercise price of outstanding options, warrants and rights ($)Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
 (a)(b)(c)
Equity compensation plans approved by security holders (1)1,415,850 (2)4.91 (4)4,214,150 (5)
      34,967 (3)   465,033 (6)
Equity compensation plans not approved by security holders---
Total1,450,8174.914,679,183

(1)
(1)Includes (a) the Amended and Restated Incentive Compensation Plan (ICP),Talen Energy Corporation 2015 SIP under which stock options, restricted stock, restricted stock units, performance units dividend equivalents and other stock-based awards may be awarded to executive officers and directors of PPL;Talen Energy Corporation and its subsidiaries and (b) the Amended and Restated Incentive Compensation Plan for Key Employees (ICPKE), under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards may be awarded to non-executive key employees of PPL and its subsidiaries; (c) the PPL 2012 SIP approved by shareowners in 2012 under which stock options, restricted stock, restricted stock units, performance units, dividend equivalents and other stock-based awards may be awarded to executive officers of PPL and its subsidiaries; and (d) theTalen Energy Directors Deferred Compensation Plan (DDCP), under which stock units may be awarded to directors of PPL.Talen Energy Corporation. See Note 128 to the Financial Statements for additional information.
(2)Total includes (i) 991,101 stock options, (ii) 265,849 restricted stock units and (iii) 158,900 performance units issued under the SIP.
All of PPL's current compensation plans under which equity securities of PPL are authorized for issuance have been approved by PPL's shareowners.
(3)Represents stock units issued under the DDCP.
Relates
(4)The weighted average exercise price relates only to common stock issuable upon the exercise of stock options awardedgranted under the ICP, SIP and ICPKESIP. The calculation of the weighted average exercise price does not include outstanding equity awards that are received or exercised for no consideration.
(5)These shares are available for grant as of December 31, 2012.  In addition,2015 under the SIP. The total number of shares which may be issued under the SIP is 5,630,000, of which the maximum number of shares for which incentive stock options may be issued is 2,000,000.
(6)These shares are available for grant as of December 31, 2012, the following other securities had been awarded and are outstanding2015 under the ICP, SIP, ICPKE and DDCP:  30,400DDCP. The total number of shares of restricted stock, 400,660 restricted stock units and 324,387 performance units under the ICP; 40,000 shares of restricted stock, 1,856 restricted stock units and 3,927 performance units under the SIP; 24,600 shares of restricted stock, 2,006,254 restricted stock units and 265,889 performance units under the ICPKE; and 467,741 stock units under the DDCP.
402
(4)Based upon the following aggregate award limitations under the ICP, SIP, ICPKE and DDCP: (a) under the ICP, 15,769,431 awards (i.e., 5% of the total PPL common stock outstanding as of April 23, 1999) granted after April 23, 1999; (b) under the SIP, 10,000,000 awards; (c) under the ICPKE, 16,573,608 awards (i.e., 5% of the total PPL common stock outstanding as of January 1, 2003) granted after April 25, 2003, reduced by outstanding awardsthat have been registered for which common stock was not yet issued as of such date of 2,373,812 resulting in a limit of 14,199,796; and (d)issuance under the DDCP the number of shares available for issuance was reduced to 2,000,000 shares in March 2012.  In addition, each of the ICP and ICPKE includes an annual award limitation of 2% of total PPL common stock outstanding as of January 1 of each year.is 500,000.


PPLTalen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Item 12 is omitted as PPLTalen Energy Supply PPL Electric, LKE, LG&E and KU meetmeets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.


145

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Talen Energy Corporation

Information for this item will be set forth in the sections entitled "Certain Relationships and Related Party Transactions" and "Corporate Governance - The Board - Director Independence" in Talen Energy Corporation's Proxy Statement in connection with the 2016 Annual Meeting of Stockholders, which will be filed with the SEC not later than 120 days after December 31, 2015, and is incorporated herein by reference.

PPLTalen Energy Supply, LLC

Item 13 is omitted as Talen Energy Supply meets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Talen Energy Corporation

Information for this item will be set forth in the sectionssection entitled "Transactions"Corporate Governance - Board Committees - Audit Committee - Fees to the Independent Auditor for 2015 and 2014" and "Approval of Fees" in Talen Energy Corporation's Proxy Statement in connection with Related Persons" and "Independence of Directors" in PPL's 2013 Notice ofthe 2016 Annual Meeting and Proxy Statement,of Stockholders, which will be filed with the SEC not later than 120 days after December 31, 2012, and is incorporated herein by reference.

PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Item 13 is omitted as PPL Energy Supply, PPL Electric, LKE, LG&E and KU meet the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

PPL Corporation

Information for this item will be set forth in the section entitled "Fees to Independent Auditor for 2012 and 2011" in PPL's 2013 Notice of Annual Meeting and Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2012,2015, and which information is incorporated herein by reference.

PPLTalen Energy Supply, LLC

The following table presents an allocation of fees billed, including expenses, by Ernst & Young LLP (EY) to Talen Energy Corporation and PPL (for services prior to June 1, 2015) for the fiscal years ended December 31, 20122015 and 2011,2014, for professional services rendered for the audit of PPLTalen Energy Supply's annual financial statements and for fees billed for other services rendered by EY.

  2012  2011 
  
(in thousands)
       
Audit fees (a) $ 2,132  $ 1,701 
Audit-related fees (b)   54    9 
Tax fees (c)   163    518 
 2015 2014
 (in thousands)
Audit fees (a)$2,646
 $1,483
Audit-related fees (b)287
 —
Tax fees (c)371
 49
All other fees—
 —
Total Fees$3,304
 $1,532

(a)
(a)Includes estimated fees for the audit of the annual financial statements and the review of the financial statements included in PPLTalen Energy Supply's Quarterly Reports on Form 10-Q (which includes subsidiaries added during 2015, such as Raven, Jade, Sapphire and MACH Gen) and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.SEC (e.g. re-marketing of certain financings).
(b)Fees forIncludes performance of specific agreed-upon procedures.
(c)Includes fees for tax advice in connection with a tax basisdue diligence and earnings and profit study, a private letter ruling related to the sale of Safe Harbor, Ironwood purchase accounting, and review, consultation and analysis related to investment tax credits and related capital expenditures on certain hydro-electric plant upgrades.
403
PPL Electric Utilities Corporation

The following table presents an allocation of fees billed, including expenses, by EY to PPL for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audit of PPL Electric's annual financial statements and for fees billed for other services rendered by EY.

  2012  2011 
  
(in thousands)
       
Audit fees (a) $ 1,319  $ 1,193 
Audit-related fees (b)   10    45 
Tax fees (c)   207    19 

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in PPL Electric's Quarterly Reports on Form 10-Q and for services in connectionconnections with statutorymerger and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.acquisition activities.

(b)Fees for consultation on a transmission and distribution study and performance of specific agreed-upon procedures.

(c)Includes fees for tax advice in connection with non-incomemerger and acquisition activities as well as tax processes, sales and use tax matters and analysisadvice related to the deductibility ofcapital expenditures on certain transmissionhydro-electric plant upgrades and distribution costs.various state and local tax issues.

LG&E and KU Energy LLC

The following table presents an allocation of fees billed, including expenses, by EY to LKE for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audits of LKE's annual financial statements and for fees billed for other services rendered by EY.

  2012  2011 
  
(in thousands)
       
Audit fees (a) $ 1,715  $ 1,528 

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in LKE's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

Louisville Gas and Electric Company

The following table presents an allocation of fees billed, including expenses, by EY to LG&E for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audits of LG&E's annual financial statements and for fees billed for other services rendered by EY.

  2012  2011 
  
(in thousands)
       
Audit fees (a) $ 731  $ 552 

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in LG&E's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

Kentucky Utilities Company

The following table presents an allocation of fees billed, including expenses, by EY to KU for the fiscal years ended December 31, 2012 and 2011, for professional services rendered for the audits of KU's annual financial statements and for fees billed for other services rendered by EY.
404
     
  2012  2011 
  
(in thousands)
       
Audit fees (a) $ 626  $ 552 

(a)Includes estimated fees for audit of annual financial statements and review of financial statements included in KU's Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC.

PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

Approval of Fees The Audit Committee of PPL has procedures for pre-approving audit and non-audit services to be provided by the independent auditor. These procedures are designed to ensure the continued independence of the independent auditor. More specifically, the use of the independent auditor to perform either audit or non-audit services is prohibited unless specifically approved in advance by the Audit Committee of PPL.Committee. As a result, of this approval process, the Audit Committee of PPLTalen Energy Corporation has pre-approved specific categories ofspecified services and authorization levels. All services outside ofother than those specified in the specified categoriesprocedures and all amounts exceeding the authorization levels are approved in advance by the Chair of the Audit Committee, of PPL, who serves as the Committee designee to review and approve audit and non-audit related services during the year. A listing of the approved audit and non-audit services is reviewed with the full Audit Committee of PPL no later than its next meeting.

The Audit Committee of PPL approved 100% of the 20122015 and 20112014 services provided by EY.

PART IVEY were pre-approved in accordance with applicable policies.


146

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Talen Energy Corporation and Talen Energy Supply, LLC

(a) The following documents are filed as part of this report:

PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
(a)  The following documents are filed as part of this report:
1.Financial Statements - Refer to the "Table of Contents" for an index of the financial statements included in this report.

2.Supplementary Data and Supplemental Financial Statement Schedule - included in response to Item 8.

Schedule I - Talen Energy Corporation's Condensed Unconsolidated Financial Statements

All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.

Schedule I - LG&E and KU Energy LLC Condensed Unconsolidated Financial Statements.
All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.
3.Exhibits
See Exhibit Index immediately following the signature pages.

See Exhibit Index immediately following the signature pages.


147
405

SHAREOWNER AND INVESTOR INFORMATION


Annual Meetings:  The 2013 annual meeting of shareowners of PPL will be held on Wednesday, May 15, 2013, at the Zoellner Arts Center, on the campus of Lehigh University in Bethlehem, Pennsylvania, in Northampton County.

Proxy and Information Statement Material:  A proxy statement and notice of PPL's annual meeting is mailed to all shareowners of record as of February 28, 2013.

PPL Annual Report: The report is published and mailed in the beginning of April to all shareowners of record.  The latest annual report can be accessed at www.pplweb.com.  If you have more than one account, or if there is more than one investor in your household, you may call the PPL Shareowner Information Line to request that only one annual report be delivered to your address.  Please provide account numbers for all duplicate mailings.

Dividends:  Subject to the declaration of dividends on PPL common stock by the PPL Board of Directors or its Executive Committee and PPL Electric preference stock by the PPL Electric Board of Directors, dividends are paid on the first business day of April, July, October and January.  The 2013 record dates for dividends are expected to be March 8, June 10, September 10 and December 10.

PPL Shareowner InformationLine (1-800-345-3085): Shareowners can obtain corporate and financial information 24 hours a day using the PPL Shareowner Information Line.  Earnings, dividends and other company news releases are available by fax or mail.  Other PPL publications, such as the annual and quarterly reports to the Securities and Exchange Commission (Forms 10-K and 10-Q), will be mailed upon request, or write to:

Manager - PPL Investor Services
Two North Ninth Street (GENTW13)
Allentown, PA  18101

FAX:  610-774-5106
Via email:  invserv@pplweb.com

PPL's Website(www.pplweb.com):  Shareowners can access PPL Securities and Exchange Commission filings, corporate governance materials, news releases, stock quotes and historical performance.  Visitors to our website can provide their email address and indicate their desire to receive future earnings or news releases automatically.

Shareowner Inquiries:

PPL Shareowner Services
Wells Fargo Bank, N.A.
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120

Toll Free:  1-800-345-3085
Outside U.S.:  651-453-2129
FAX:  651-450-4085
shareowneronline.com

Online Account Access:  Registered shareowners can activate their account for online access by visiting shareowneronline.com.

Dividend Reinvestment and Direct Stock Purchase Plan (Plan):  PPL offers investors the opportunity to acquire shares of PPL common stock through its Plan.  Through the Plan, participants are eligible to invest up to $25,000 per calendar month in PPL common stock.  Shareowners may choose to have dividends on their PPL common stock fully or partially reinvested in PPL common stock or can receive full payment of cash dividends by check or EFT.  Participants in the Plan may choose to have their common stock certificates deposited into their Plan account.

Direct Registration System:  PPL participates in the Direct Registration System (DRS).  Shareowners may choose to have their common stock certificates converted to book entry form within the DRS by submitting their certificates to PPL's transfer agent.
406
Listed Securities:

New York Stock Exchange

PPL Corporation:
Common Stock (Code:  PPL)

Corporate Units issued 2010 (Code:  PPLPRU)

Corporate Units issued 2011 (Code:  PPLPRW)

PPL Capital Funding, Inc.:
2007 Series A Junior Subordinated Notes due 2067 (Code:  PPL/67)

Fiscal Agents:

Stock Transfer Agent and Registrar; Dividend Reinvestment Plan Agent
Wells Fargo Bank, N.A.
Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120

Toll Free:  1-800-345-3085
Outside U.S.:  651-453-2129

Dividend Disbursing Office
PPL Investor Services
Two North Ninth Street (GENTW13)
Allentown, PA  18101

FAX:  610-774-5106
Via email:  invserv@pplweb.com

Or call the PPL Shareowner Information Line
Toll Free:  1-800-345-3085

1945 Mortgage Bond Trustee, Transfer and Bond Interest Paying Agent
Deutsche Bank Trust Company Americas
5022 Gate Parkway (Suite 200)
Jacksonville, FL  32256

Toll Free:  1-800-735-7777
FAX:  615-866-3887

Indenture Trustee
The Bank of New York Mellon
101 Barclay Street
New York, NY 10286

407
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PPL Corporation
(Registrant)

By  /s/ William H. Spence
William H. Spence -
Chairman, President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
By  /s/ William H. Spence
William H. Spence -
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)
By  /s/ Paul A. Farr
Paul A. Farr -
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
By  /s/ Vincent Sorgi
Vincent Sorgi -
Vice President and Controller
(Principal Accounting Officer)
Directors:
Frederick M. BernthalVenkata Rajamannar Madabhushi
John W. ConwayCraig A. Rogerson
Steven G. ElliottWilliam H. Spence
Louise K. GoeserNatica von Althann
Stuart E. GrahamKeith H. Williamson
Stuart Heydt
By  /s/ William H. Spence
William H. Spence, Attorney-in-factDate:  February 28, 2013
408
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PPL Energy Supply, LLC
(Registrant)

By  /s/ David G. DeCampli
David G. DeCampli -
PresidentTalen Energy Corporation
(Registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
By  /s/ David G. DeCampli
David G. DeCampli -
President
(Principal Executive Officer)
   
By /s/ Paul A. Farr  
Paul A. Farr -  
Director, President and Chief Executive Vice President
(Principal Financial Officer)Officer  
   
Date: February 26, 2016

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

  
By /s/ Vincent Sorgi
Vincent Sorgi -
Vice President and Controller
(Principal Accounting Officer)
Managers:
/s/ David G. DeCampli
David G. DeCampli
/s/ Paul A. Farr  
Paul A. Farr  
Director, President and Chief Executive Officer  
   
/s/ Robert J. GreyBy /s/ Jeremy R. McGuire  
Robert J. GreyJeremy R. McGuire 
Senior Vice President, Chief Financial Officer and Chief Accounting Officer
   
   
/s/ William H. SpenceRalph Alexander, Director  
William H. SpenceFrederick M. Bernthal, Director  
Edward J. Casey Jr., Director
Philip G. Cox, Director
Louise K. Goeser, Director
Stuart E. Graham, Director
Michael B. Hoffman, Director  
   
By /s/ Jeremy R. McGuire  
Jeremy R. McGuire, Attorney-in-fact  
   
Date: February 28, 201326, 2016  

148

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PPL Electric Utilities Corporation
(Registrant)

By  /s/ Gregory N. Dudkin
Gregory N. Dudkin -
PresidentTalen Energy Supply, LLC
(Registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
   
By /s/ Gregory N. Dudkin
Gregory N. Dudkin -
President
(Principal Executive Officer)
By  /s/ Vincent Sorgi
Vincent Sorgi -
Vice President and Chief Accounting Officer
(Principal Financial and Accounting Officer)
Directors:
/s/ William H. Spence/s/ Gregory N. Dudkin
William H. SpenceGregory N. Dudkin
/s/ Paul A. Farr/s/ Dean A. Christiansen  
Paul A. Farr Dean A. Christiansen
Manager, President and Chief Executive Officer  
   
/s/ Robert J. Grey
Robert J. Grey
Date: February 28, 201326, 2016  
410
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant has duly caused this report to be signedand in the capacities and on its behalf by the undersigned, thereunto duly authorized.date indicated.

LG&E and KU Energy LLC
(Registrant)

By  /s/ Victor A. Staffieri
Victor A. Staffieri -
Chairman of the Board, Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
   
By /s/ Victor A. Staffieri
Victor A. Staffieri -
Chairman of the Board, Chief Executive Officer and President
(Principal Executive Officer)
By  /s/ Kent W. Blake
Kent W. Blake -
Chief Financial Officer
(Principal Financial Officer and
Principal Accounting Officer)
Directors:
/s/ Paul A. Farr/s/ William H. Spence  
Paul A. Farr William H. Spence 
/s/ Chris Hermann
/s/ Victor A. Staffieri
Chris HermannVictor A. Staffieri
/s/ S. Bradford Rives
/s/ Paul W. Thompson
S. Bradford RivesPaul W. ThompsonManager, President and Chief Executive Officer  
   
By /s/ Jeremy R. McGuire  
Jeremy R. McGuire  
Manager, Senior Vice President, Chief Financial Officer and Chief Accounting Officer  
   
By /s/ Clarence J. Hopf Jr.  
Date:  February 28, 2013

411
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Louisville Gas and Electric Company
(Registrant)

By  /s/ Victor A. StaffieriClarence J. Hopf Jr.  
Victor A. Staffieri -
Chairman of the Board, Chief Executive Officer and PresidentManager  
   
By /s/ Paul M. Breme  
Paul M. Breme  
Manager  
   
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
By  /s/ Victor A. Staffieri
Victor A. Staffieri -
Chairman of the Board, Chief Executive Officer and President
(Principal Executive Officer)
By  /s/ Kent W. Blake
Kent W. Blake -
Chief Financial Officer
(Principal Financial Officer and
Principal Accounting Officer)
Directors:
/s/ Paul A. Farr/s/ William H. Spence
Paul A. FarrWilliam H. Spence
/s/ Chris Hermann
/s/ Victor A. Staffieri
Chris HermannVictor A. Staffieri
/s/ S. Bradford Rives
/s/ Paul W. Thompson
S. Bradford RivesPaul W. Thompson
Date: February 28, 201326, 2016  


149
412
SIGNATURES

Pursuant to the requirementsTable of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Kentucky Utilities Company
(Registrant)

By  /s/ Victor A. Staffieri
Victor A. Staffieri -
Chairman of the Board, Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
By  /s/ Victor A. Staffieri
Victor A. Staffieri -
Chairman of the Board, Chief Executive Officer and President
(Principal Executive Officer)
By  /s/ Kent W. Blake
Kent W. Blake -
Chief Financial Officer
(Principal Financial Officer and
Principal Accounting Officer)
Directors:
/s/ Paul A. Farr/s/ William H. Spence
Paul A. FarrWilliam H. Spence
/s/ Chris Hermann
/s/ Victor A. Staffieri
Chris HermannVictor A. Staffieri
/s/ S. Bradford Rives
/s/ Paul W. Thompson
S. Bradford RivesPaul W. Thompson
Date:  February 28, 2013
EXHIBIT INDEX

The following Exhibits indicated by an asterisk preceding the Exhibit number are filed herewith. The balance of the Exhibits havehas heretofore been filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein by reference. Exhibits indicated by a [_]+ are filed or listed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

3(a)
2.1-Amended and Restated ArticlesSeparation Agreement, dated as of Incorporation ofJune 9, 2014, among PPL Corporation, effectiveTalen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Raven Power Holdings LLC, C/R Energy Jade, LLC and Sapphire Power Holdings LLC (incorporated by reference to Exhibit 2.1 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) filed on June 12, 2014)
2.2-Transaction Agreement, dated as of May 21, 2008 (Exhibit 3(i)June 9, 2014, among PPL Corporation, Talen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Talen Energy Merger Sub, Inc., C/R Energy Jade, LLC, Sapphire Power Holdings LLC and Raven Power Holdings LLC (incorporated by reference to Exhibit 2.2 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944)) filed on June 12, 2014)
2.3-Amendment No. 1, dated as of October 23, 2014, to the Transaction Agreement, dated as of June 9, 2014, among PPL Corporation, Talen Energy Holdings, Inc., Talen Energy Corporation, PPL Energy Supply, LLC, Talen Energy Merger Sub, Inc., C/R Energy Jade, LLC, Sapphire Power Holdings LLC and Raven Power Holdings LLC (incorporated by reference to Exhibit 2.3 to Talen Energy Corporation Registration Statement on Form S-1 (File No. 333-199888) filed on November 5, 2014)
2.4-Purchase and Sale Agreement, dated as of July 18, 2015, by and among Talen Energy Supply, LLC, the sellers named therein, Silver Oak Capital, LLC, as seller representative and MACH Gen, LLC, with respect to 100% of the membership interests in MACH Gen, LLC (incorporated by reference to Exhibit 2.1 to Talen Energy Corporation Form 8-K Report (File No. 1-11459) dated May 21, 2008)1-37388)) filed on July 20, 2015)
2.5-Asset Purchase Agreement, dated as of October 7, 2015, by and between Holtwood, LLC and BIF III Holtwood LLC (incorporated by reference to Exhibit 2.1 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on October 9, 2015)
3(b)2.6*-Amended and Restated ArticlesPurchase and Sale Agreement, dated as of December 22, 2015, by and between Talen Generation, LLC and TransCanada Facility USA, Inc.
3.1-Amended and Restated Certificate of Incorporation of PPL Electric UtilitiesTalen Energy Corporation effective as of May 2, 2006 (Exhibit 3(a)(incorporated by reference to PPL Electric UtilitiesExhibit 3.1 to Talen Energy Corporation Form 10-Q8-K Report (File No. 1-905) for the quarter ended March 31, 2006)1-37388) filed on June 2, 2015)
3.2-Amended and Restated Bylaws of Talen Energy Corporation (incorporated by reference to Exhibit 3.2 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
3(c)-13.3-Certificate of Formation of Talen Energy Supply (f/k/a PPL Energy Supply, LLC, effective as of November 14, 2000 (ExhibitLLC) (incorporated by reference to Exhibit 3.1 to PPL Energy Supply, LLC Form S-4 (Registration Statement No. 333-74794)) filed on December 7, 2001)
3(c)-23.4-Certificate of Amendment of Talen Energy Supply (f/k/a PPL Energy Supply, LLC, effective as of November 12, 2002 (ExhibitLLC) (incorporated by reference to Exhibit 3(c)-2 to PPL Energy Supply, LLC Form 10-K Report (File No. 1-32944) for the year ended December 31, 2011))
3(d)3.5-Amended and Restated BylawsCertificate of Amendment of Talen Energy Supply, LLC (f/k/a PPL Corporation, effective as of May 19, 2010 (Exhibit 99.1Energy Supply, LLC) dated June 1, 2015 (incorporated by reference to PPLExhibit 3.5 to Talen Energy Corporation Form 8-K10-Q Report (File No. 1-11459) dated May 24, 2010)1-37388) for the quarter ended September 30, 2015)
3(e)-Amended and Restated Bylaws of PPL Electric Utilities Corporation, effective as of March 30, 2006 (Exhibit 3.2 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated March 30, 2006)
3(f)3.6-Limited Liability Company Agreement of Talen Energy Supply (f/k/a PPL Energy Supply, LLC, effective as of March 20, 2001 (ExhibitLLC) (incorporated by reference to Exhibit 3.2 to PPL Energy Supply, LLC Form S-4 (Registration Statement No. 333-74794)) filed on December 7, 2001)
3(g)4.1-Articles of Organization of LG&E and KU Energy LLC, effective as of December 29, 2003 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173665))
3(h)-Amended and Restated Operating Agreement of LG&E and KU Energy LLC, effective as of November 1, 2010 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173665))
3(i)-1-Amended and Restated Articles of Incorporation of Louisville Gas and Electric Company, effective as of November 6, 1996 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173676))
3(i)-2-Articles of Amendment to Articles of Incorporation of Louisville Gas and Electric Company, effective as of April 6, 2004 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173676))
3(j)-Bylaws of Louisville Gas and Electric Company, effective as of December 16, 2003 (Exhibit 3(c) to Registration Statement filed on Form S-4 (File No. 333-173676))
3(k)-1-Amended and Restated Articles of Incorporation of Kentucky Utilities Company, effective as of December 14, 1993 (Exhibit 3(a) to Registration Statement filed on Form S-4 (File No. 333-173675))
3(k)-2-Articles of Amendment to Articles of Incorporation of Kentucky Utilities Company, effective as of April 8, 2004 (Exhibit 3(b) to Registration Statement filed on Form S-4 (File No. 333-173675))
3(l)-Bylaws of Kentucky Utilities Company, effective as of December 16, 2003 (Exhibit 3(c) to Registration Statement filed on Form S-4 (File No. 333-173675))
4(a)-Pollution Control Facilities LoanStockholder Agreement, dated as of MayJune 1, 1973,2015, by and between PPL Electric UtilitiesRaven Power Holdings LLC, C/R Energy Jade, LLC and Sapphire Power Holdings LLC and Talen Energy Corporation and the Lehigh County Industrial Development Authority (Exhibit 5(z)(incorporated by reference to Registration Statement No. 2-60834)
4(b)-1-Amended and Restated Employee Stock Ownership Plan, dated January 12, 2007 (Exhibit 4(a) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
414
4(b)-2-Amendment No. 1 to said Employee Stock Ownership Plan, dated July 2, 2007 (Exhibit 4(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2007)
4(b)-3-Amendment No. 2 to said Employee Stock Ownership Plan, dated December 13, 2007 (Exhibit 4(a)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2007)
4(b)-4-Amendment No. 3 to said Employee Stock Ownership Plan, dated August 19, 2009 (Exhibit 4(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2009)
4(b)-5-Amendment No. 4 to said Employee Stock Ownership Plan, dated December 2, 2009 (Exhibit 4(a)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2009)
4(b)-6-Amendment No. 5 to said Employee Stock Ownership Plan, dated November 17, 2010 (Exhibit 4(b)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(b)-7-Amendment No. 6 to said Employee Stock Ownership Plan, dated January 18, 2012 (Exhibit 4(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2012)
4(b)-8-Amendment No. 7 to said Employee Stock Ownership Plan, dated May 30, 2012 (Exhibit 4(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2012)
4(b)-9-Amendment No. 8 to said Employee Stock Ownership Plan, dated July 17, 2012 (Exhibit 4(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2012)
*4(b)-10
-Amendment No. 9 to said Employee Stock Ownership Plan, dated December 21, 2012
4(c)-Trust Deed constituting £150 million 9 ¼ percent Bonds due 2020, dated November 9, 1995, between South Wales Electric plc and Bankers Trustee Company Limited (Exhibit 4(k) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2004)
4(d)-1-Indenture, dated as of November 1, 1997, among PPL Corporation, PPL Capital Funding, Inc. and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (ExhibitExhibit 4.1 to PPLTalen Energy Corporation Form 8-K Report (File No. 1-11459) dated November 12, 1997)1-37388) filed on June 2, 2015)
4(d)-2-Supplemental Indenture No. 7, dated as of July 1, 2007, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated July 16, 2007)
4(d)-3-Supplemental Indenture No. 8, dated as of June 14, 2012, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 14, 2012)
4(d)-4-Supplemental Indenture No. 9, dated as of October 15, 2012, to said Indenture (Exhibit 4(b) to PPL Corporation Form 8-K Report (File No. 1-11459) dated October 15, 2012)
4(e)-Indenture, dated as of March 16, 2001, among WPD Holdings UK, Bankers Trust Company, as Trustee, Principal Paying Agent, and Transfer Agent and Deutsche Bank Luxembourg, S.A., as Paying and Transfer Agent (Exhibit 4(g) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2009)
4(f)-1-Indenture, dated as of August 1, 2001, by PPL Electric Utilities Corporation and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 21, 2001)
4(f)-2-Supplemental Indenture No. 4, dated as of February 1, 2005, to said Indenture (Exhibit 4(g)-5 to PPL Electric Utilities Corporation Form 10-K Report (File No. 1-905) for the year ended December 31, 2004)
415
4(f)-3-Supplemental Indenture No. 5, dated as of May 1, 2005, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended June 30, 2005)
4(f)-4-Supplemental Indenture No. 6, dated as of December 1, 2005, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated December 22, 2005)
4(f)-5-Supplemental Indenture No. 7, dated as of August 1, 2007, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 14, 2007)
4(f)-6-Supplemental Indenture No. 9, dated as of October 1, 2008, to said Indenture (Exhibit 4(c) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 31, 2008)
4(f)-7-Supplemental Indenture No. 10, dated as of May 1, 2009, to said Indenture (Exhibit 4(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated May 22, 2009)
4(f)-8-Supplemental Indenture No. 11, dated as of July 1, 2011, to said Indenture (Exhibit 4.1 to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 13, 2011)
4(f)-9-Supplemental Indenture No. 12, dated as of July 1, 2011, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated July 18, 2011)
4(f)-10-Supplemental Indenture No. 13, dated as of August 1, 2011, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 23, 2011)
4(f)-11-Supplemental Indenture No. 14, dated as of August 1, 2012, to said Indenture (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 24, 2012)
4(g)-14.2-Indenture, dated as of October 1, 2001, by PPL Energy Supply, LLC and The Bank of New York Mellon, as successor to JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee (Exhibit(incorporated by reference to Exhibit 4.1 to PPL Energy Supply, LLC Form S-4 (Registration Statement No. 333-74794)) filed on December 7, 2001)
4(g)- 24.3-Supplemental Indenture No. 2, dated as of August 15, 2004, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(h)-4 to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2004)
4(g)-34.4-Supplemental Indenture No. 3, dated as of October 15, 2005, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(a) to PPL Energy Supply, LLC Form 8-K Report (File No. 333-74794) datedfiled on October 28, 2005)

150

4(g)-4
4.5-
Form of Note for PPL Energy Supply, LLC's $300 million aggregate principal amount of 5.70% REset Put Securities due 2035 (REPSSM) (Exhibit(REPSSM) (incorporated by reference to Exhibit 4(b) to PPL Energy Supply, LLC Form 8-K Report (File No. 333-74794) datedfiled on October 28, 2005)
4(g)-54.6-Supplemental Indenture No. 4, dated as of May 1, 2006, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(a) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended June 30, 2006)
4(g)-64.7-Supplemental Indenture No. 6, dated as of July 1, 2006, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(c) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended June 30, 2006)
4(g)-74.8-Supplemental Indenture No. 7, dated as of December 1, 2006, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(f)-10 to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2006)
4(g)-84.9-Supplemental Indenture No. 8, dated as of December 1, 2007, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(b) to PPL Energy Supply, LLC Form 8-K Report (File No. 333-74794) datedfiled on December 20, 2007)
4(g)-94.10-Supplemental Indenture No. 9, dated as of March 1, 2008, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(b) to PPL Energy Supply, LLC Form 8-K Report (File No. 333-74794) datedfiled on March 14, 2008)
416
4(g)-104.11-Supplemental Indenture No. 10, dated as of July 1, 2008, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(b) to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) datedfiled on July 21, 2008)
4(g)-114.12-Supplemental Indenture No. 11, dated as of December 1, 2011, to said Indenture (Exhibit(incorporated by reference to Exhibit 4(a) to PPL CorporationEnergy Supply, LLC Form 8-K Report (File No. 1-1149) dated1-32944) filed on December 16, 2011)
4(h)-1-Trust Deed constituting £200 million 5.875 percent Bonds due 2027, dated March 25, 2003, between Western Power Distribution (South West) plc and J.P. Morgan Corporate Trustee Services Limited (Exhibit 4(o)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2004)
4(h)-2-Supplement, dated May 27, 2003, to said Trust Deed, constituting £50 million 5.875 percent Bonds due 2027 (Exhibit 4(o)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2004)
4(i)-1-Pollution Control Facilities Loan Agreement, dated as of February 1, 2005, between PPL Electric Utilities Corporation and the Lehigh County Industrial Development Authority (Exhibit 10(ff) to PPL Electric Utilities Corporation Form 10-K Report (File No. 1-905) for the year ended December 31, 2004)
4(i)-2-Pollution Control Facilities Loan Agreement, dated as of May 1, 2005, between PPL Electric Utilities Corporation and the Lehigh County Industrial Development Authority (Exhibit 10(a) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended June 30, 2005)
4(i)-3-Pollution Control Facilities Loan Agreement, dated as of October 1, 2008, between Pennsylvania Economic Development Financing Authority and PPL Electric Utilities Corporation (Exhibit 4(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated October 31, 2008)
4(j)-Trust Deed constituting £105 million 1.541 percent Index-Linked Notes due 2053, dated December 1, 2006, between Western Power Distribution (South West) plc and HSBC Trustee (CI) Limited (Exhibit 4(i) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
4(k)-Trust Deed constituting £120 million 1.541 percent Index-Linked Notes due 2056, dated December 1, 2006, between Western Power Distribution (South West) plc and HSBC Trustee (CI) Limited (Exhibit 4(j) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
4(l)-Trust Deed constituting £225 million 4.80436 percent Notes due 2037, dated December 21, 2006, between Western Power Distribution (South Wales) plc and HSBC Trustee (CI) Limited (Exhibit 4(k) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
4(m)-1-Subordinated Indenture, dated as of March 1, 2007, between PPL Capital Funding, Inc., PPL Corporation and The Bank of New York, as Trustee (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated March 20, 2007)
4(m)-24.13-Supplemental Indenture No. 1,12, dated as of March 1, 2007,February 12, 2013, to said Subordinated Indenture (Exhibit 4(b)(incorporated by reference to Exhibit 4.1 to PPL CorporationEnergy Supply, LLC Form 8-K Report (File No. 1-11459) dated March 20, 2007)1-32944) filed on February 13, 2013)
4(m)-34.14-Supplemental Indenture No. 2,13, dated as of June 28, 2010,May 19, 2015, to said Subordinated Indenture (Exhibit 4.3(incorporated by reference to Exhibit 4.1 to PPL CorporationEnergy Supply, LLC Form 8-K Report (File No. 1-11459) dated June 30, 2010)1-32944) filed on May 19, 2015)
4(m)-44.15-Officer's Certificate, dated May 19, 2015, pursuant to Supplemental Indenture No. 3, dated as13, establishing the form and certain terms of April 15, 2011,the Notes (incorporated by reference to said Subordinated Indenture (Exhibit 4.3Exhibit 4.2 to PPL CorporationEnergy Supply, LLC Form 8-K Report (File No. 1-11459) dated April1-32944) filed on May 19, 2011)2015)
4.16-Form of 6.500% Senior Notes due 2025 (incorporated by reference to Exhibit 4.3 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) filed on May 19, 2015)
4(n)-14.17-Registration Rights Agreement, dated May 19, 2015, among PPL Energy Supply, LLC and Citigroup Global Markets Inc., BNP Paribas Securities Corp, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co., J.P. Morgan Securities LLC and Morgan Stanley & Co. LLC, as representatives of the initial purchasers (incorporated by reference to Exhibit 4.4 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) filed on May 19, 2015)
4.18-Series 2009A Exempt Facilities Loan Agreement, dated as of April 1, 2009, between PPL Energy Supply, LLC and Pennsylvania Economic Development Financing Authority (Exhibit(incorporated by reference to Exhibit 4(a) to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) datedfiled on April 9, 2009)
4.19-First Supplement to Series 2009A Exempt Facilities Loan Agreement, dated September 1, 2015, between Talen Energy Supply, LLC and Pennsylvania Economic Development Financing Authority (incorporated by reference to Exhibit 4(a) to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on September 1, 2015)
417
4(n)-24.20-Series 2009B Exempt Facilities Loan Agreement, dated as of April 1, 2009, between PPL Energy Supply, LLC and Pennsylvania Economic Development Financing Authority (Exhibit(incorporated by reference to Exhibit 4(b) to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) datedfiled on April 9, 2009)
4.21-First Supplement to Series 2009B Exempt Facilities Loan Agreement, dated September 1, 2015, between Talen Energy Supply, LLC and Pennsylvania Economic Development Financing Authority (incorporated by reference to Exhibit 4(b) to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on September 1, 2015)
4(n)-34.22-Series 2009C Exempt Facilities Loan Agreement, dated as of April 1, 2009, between PPL Energy Supply, LLC and Pennsylvania Economic Development Financing Authority (Exhibit(incorporated by reference to Exhibit 4(c) to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) datedfiled on April 9, 2009)
4(o)4.23-Trust Deed constituting £200 million 5.75 percent Notes due 2040,First Supplement to Series 2009C Exempt Facilities Loan Agreement, dated March 23, 2010,September 1, 2015, between Western Power Distribution (South Wales) plcTalen Energy Supply, LLC and HSBC Corporate Trustee Company (UK) Limited (Exhibit 4(a)Pennsylvania Economic Development Financing Authority (incorporated by reference to PPLExhibit 4(c) to Talen Energy Corporation Form 10-Q8-K Report (File No. 1-11459) for the quarter ended March 31, 2010)1-37388) filed on September 1, 2015)

151

4(p)-Trust Deed constituting £200 million 5.75 percent Notes due 2040, dated March 23, 2010, between Western Power Distribution (South West) plc and HSBC Corporate Trustee Company (UK) Limited (Exhibit 4(b) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2010)
4(q)-14.24-Indenture, dated as of October 1, 2010, between Kentucky Utilities CompanyJuly 10, 2014, among RJS Power Holdings LLC, the guarantors party thereto and The Bank of New York Mellon, as Trustee (Exhibit 4(q)-1(incorporated by reference to Exhibit 4.16 to Talen Energy Corporation Registration Statement on Form S-1 (File No. 333-199888) filed on November 5, 2014)
4.25-Supplemental Indenture No. 1, dated as of June 1, 2015, among PPL Energy Supply, LLC, RJS Power Holdings LLC, RJS Power LLC and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.3 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
4.26-Third Supplemental Indenture, dated as of February 12, 2013, to Trust Indenture dated as of June 1, 1999, among PPL Ironwood, LLC, The Bank of New York Mellon, as Trustee and The Bank of New York Mellon, as Depositary Bank (incorporated by reference to Exhibit 10(hh) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)2013)
4(q)-210.1-Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(q)-3-Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(q)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(r)-1-Indenture, dated as of October 1, 2010, between Louisville Gas and Electric Company and The Bank of New York Mellon, as Trustee (Exhibit 4(r)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(r)-2-Supplemental Indenture No. 1, dated as of October 15, 2010, to said Indenture (Exhibit 4(r)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(r)-3-Supplemental Indenture No. 2, dated as of November 1, 2010, to said Indenture (Exhibit 4(r)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(s)-1-Indenture, dated as of November 1, 2010, between LG&E and KU Energy LLC and The Bank of New York Mellon, as Trustee (Exhibit 4(s)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(s)-2-Supplemental Indenture No. 1, dated as of November 1, 2010, to said Indenture (Exhibit 4(s)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(s)-3-Supplemental Indenture No. 2, dated as of September 1, 2011, to said Indenture (Exhibit 4(a) to PPL Corporation Form 8-K Report (File No. 1-11459) dated September 30, 2011)
4(t)-1-2002 Series A Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(t)-2-Amendment No. 1 dated as of September 1, 2010 to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(w)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
418
4(u)-1-2002 Series B Carroll County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(u)-2-Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(x)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(v)-1-2002 Series C Carroll County Loan Agreement, dated July 1, 2002, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(y)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(v)-2-Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(y)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(w)-1-2004 Series A Carroll County Loan Agreement, dated October 1, 2004 and amended and restated as of September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(w)-2-Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(z)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(x)-1-2006 Series B Carroll County Loan Agreement, dated October 1, 2006 and amended and restated September 1, 2008, by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(x)-2-Amendment No. 1 dated as of September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(aa)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(y)-1-2007 Series A Carroll County Loan Agreement, dated March 1, 2007, by and between Kentucky Utilities Company and County of Carroll, Kentucky (Exhibit 4(bb)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(y)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(bb)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(z)-1-2008 Series A Carroll County Loan Agreement, dated August 1, 2008 by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(z)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Carroll, Kentucky (Exhibit 4(cc)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(aa)-1-2000 Series A Mercer County Loan Agreement, dated May 1, 2000 and amended and restated as of September 1, 2008, by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(dd)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(aa)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(dd)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
419
4(bb)-1-2002 Series A Mercer County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(bb)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Mercer, Kentucky (Exhibit 4(ee)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(cc)-1-2002 Series A Muhlenberg County Loan Agreement, dated February 1, 2002, by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(cc)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Muhlenberg, Kentucky (Exhibit 4(ff)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(dd)-1-2007 Series A Trimble County Loan Agreement, dated March 1, 2007, by and between Kentucky Utilities Company, and County of Trimble, Kentucky (Exhibit 4(gg)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(dd)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Kentucky Utilities Company, and County of Trimble, Kentucky (Exhibit 4(gg)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ee)-1-2000 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated May 1, 2000 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(hh)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ee)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(hh)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ee)-3-Amendment No. 2 dated as of October 1, 2011, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ee)-3 to Louisville Gas and Electric Company Form 10-K Report (File No. 1-2893) for the year ended December 31, 2011)
4(ff)-1-2001 Series A Jefferson County Loan Agreement, dated July 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(ii)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ff)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(ii)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(gg)-1-2001 Series A Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(gg)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(jj)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(hh)-1-2001 Series B Jefferson County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
420
4(hh)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Jefferson County, Kentucky (Exhibit 4(kk)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ii)-1-2003 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated October 1, 2003, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ii)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(ll)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(jj)-1-2005 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated February 1, 2005 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(jj)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(mm)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(kk)-1-2007 Series A Louisville/Jefferson County Metro Government Loan Agreement, dated as of March 1, 2007 and amended and restated as of September 1, 2008, by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(kk)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(nn)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(ll)-2007 Series B Louisville/Jefferson County Metro Government Amended and Restated Loan Agreement, dated November 1, 2010, by and between Louisville Gas and Electric Company and Louisville/Jefferson County Metro Government, Kentucky (Exhibit 4(oo) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(mm)-1-2000 Series A Trimble County Loan Agreement, dated August 1, 2000, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(pp)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(mm)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(pp)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(nn)-1-2001 Series A Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(qq)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(nn)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and the County of Trimble, Kentucky (Exhibit 4(qq)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(oo)-1-2001 Series B Trimble County Loan Agreement, dated November 1, 2001, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
421
4(oo)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(rr)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(pp)-1-2002 Series A Trimble County Loan Agreement, dated July 1, 2002, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(ss)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(pp)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(ss)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(qq)-1-2007 Series A Trimble County Loan Agreement, dated March 1, 2007, by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(tt)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(qq)-2-Amendment No. 1 dated September 1, 2010, to said Loan Agreement by and between Louisville Gas and Electric Company, and County of Trimble, Kentucky (Exhibit 4(tt)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
4(rr)-1-Indenture, dated April 21, 2011, between PPL WEM Holdings PLC, as Issuer, and The Bank of New York Mellon, as Trustee (Exhibit 10.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 21, 2011)
4(rr)-2-Supplemental Indenture No. 1, dated April 21, 2011, to said Indenture (Exhibit 10.3 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 21, 2011)
4(ss)-1-Trust Deed, dated April 27, 2011, by and among Western Power Distribution (East Midlands) plc and Western Power Distribution (West Midlands) plc, as Issuers, and HSBC Corporate Trustee Company (UK) Limited as Note Trustee (Exhibit 4.1 to PPL Corporation Form 8-K Report (File No.1-11459) dated May 17, 2011)
4(ss)-2-Final Terms of WPD West Midlands £800,000,000 5.75 per cent Notes due 2032 (Exhibit 1.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 17,  2011)
4(ss)-3-Final Terms of WPD East Midlands £600,000,000 5.25 per cent Notes due 2023 (Exhibit 1.2 to PPL Corporation Form 8-K Report (File No. 1-11459 ) dated May 17, 2011)
4(ss)-4-Final Terms of WPD East Midlands £100,000,000 Index Linked Notes due 2043 (Exhibit 1.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated June 2, 2011)
4(ss)-5-Final Terms of WPD East Midlands £100,000,000 5.25% Notes due 2023 (Exhibit 1.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 19, 2012)
4(tt)-Agency Agreement, dated April 27, 2011, by and among Western Power Distribution (East Midlands) plc and Western Power Distribution (West Midlands) plc, as Issuers, and HSBC Corporate Trustee Company (UK) Limited and HSBC Bank plc (Exhibit 4.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated May 17, 2011)
10(a)-Generation SupplyEmployee Matters Agreement, dated as of June 20, 2001, between PPL Electric Utilities Corporation and PPL EnergyPlus, LLC (Exhibit 10.5 to PPL Energy Supply, LLC Form S-4 (Registration Statement No. 333-74794))
10(b)-1-Master Power Purchase and Sale Agreement, dated as of October 15, 2001, between NorthWestern Energy Division (successor in interest to The Montana Power Company) and PPL Montana, LLC (Exhibit 10(g) to PPL Montana, LLC Form 10-K Report (File No. 333-50350) for the year ended December 31, 2001)
422
10(b)-2-Confirmation Letter, dated July 5, 2006, between PPL Montana, LLC and NorthWestern Corporation (PPL Corporation and PPL Energy Supply, LLC Form 8-K Reports (File Nos. 1-11459 and 333-74794) dated July 6, 2006)
10(c)-Guaranty, dated as of December 21, 2001, from PPL Energy Supply, LLC in favor of LMB Funding, Limited Partnership (Exhibit 10(j) to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2001)
10(d)-1-Agreement for Lease, dated as of December 21, 2001, between LMB Funding, Limited Partnership and Lower Mt. Bethel Energy, LLC (Exhibit 10(m) to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2003)
10(d)-2-Amendment No. 1 to said Agreement for Lease, dated as of September 16, 2002, between LMB Funding, Limited Partnership and Lower Mt. Bethel Energy, LLC (Exhibit 10(m)-1 to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2003)
10(e)-1-Lease Agreement, dated as of December 21, 2001, between LMB Funding, Limited Partnership and Lower Mt. Bethel Energy, LLC (Exhibit 10(n) to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2003)
10(e)-2-Amendment No. 1 to said Lease Agreement, dated as of September 16, 2002, between LMB Funding, Limited Partnership and Lower Mt. Bethel Energy, LLC (Exhibit 10(n)-1 to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2003)
10(f)-Facility Lease Agreement (BA 1/2) between PPL Montana, LLC and Montana OL3, LLC (Exhibit 4.7a to PPL Montana, LLC Form S-4 (Registration Statement No. 333-50350))
10(g)-Facility Lease Agreement (BA 3) between PPL Montana, LLC and Montana OL4, LLC (Exhibit 4.8a to PPL Montana, LLC Form S-4 (Registration Statement No. 333-50350))
10(h)-Services Agreement, dated as of July 1, 2000,9, 2014, among PPL Corporation, PPLTalen Energy Funding Corporation, C/R Energy Jade, LLC, Sapphire Power Holdings LLC and its direct and indirect subsidiaries in various tiers, PPL Capital Funding, Inc., PPL Gas Utilities Corporation, PPL Services Corporation and CEP Commerce,Raven Power Holdings LLC (Exhibit 10.20(incorporated by reference to PPL Energy Supply, LLC Form S-4 (Registration Statement No. 333-74794))
10(i)-1-Asset Purchase Agreement, dated as of June 1, 2004, by and between PPL Sundance Energy, LLC, as Seller, and Arizona Public Service Company, as Purchaser (Exhibit 10(a) to PPL Corporation and PPL Energy Supply, LLC Form 10-Q Reports (File Nos. 1-11459 and 333-74794) for the quarter ended June 30, 2004)
10(i)-2-Amendment No. 1, dated December 14, 2004, to said Asset Purchase Agreement (Exhibit 99.1 to PPL Corporation and PPL Energy Supply, LLC Form 8-K Reports (File Nos. 1-11459 and 333-74794) dated December 15, 2004)
10(j)-1-Receivables Sale Agreement, dated as of August 1, 2004, between PPL Electric Utilities Corporation, as Originator, and PPL Receivables Corporation, as Buyer (Exhibit 10(d) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended June 30, 2004)
10(j)-2-Amendment No. 1, dated as of August 5, 2008, to said Receivables Sale Agreement, between PPL Electric Utilities Corporation, as Originator, and PPL Receivables Corporation, as Buyer (Exhibit 10(b) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 6, 2008)
10(j)-3-Credit and Security Agreement, dated as of August 5, 2008, among PPL Receivables Corporation, PPL Electric Utilities Corporation, Victory Receivables Corporation, the Liquidity Banks from time to time party thereto and The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (Exhibit 10(a) to PPL Electric Utilities Corporation Form 8-K Report (File No. 1-905) dated August 6, 2008)

423
10(j)-4-Amendment No. 1, dated as of July 28, 2009, to said Credit and Security Agreement (Exhibit 10(a) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended September 30, 2009)
10(j)-5-Amendment No. 2, dated as of July 27, 2010, to said Credit and Security Agreement (Exhibit 10(g) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended June 30, 2010)
10(j)-6-Amendment No. 3, dated as of December 23, 2010, to said Credit and Security Agreement (Exhibit 10(j)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
10(j)-7-Amendment No. 4, dated as of March 31, 2011, to said Credit and Security Agreement (Exhibit 10(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2011)
10(j)-8-Amendment No. 5, dated as of July 26, 2011, to said Credit and Security Agreement (Exhibit 10(c) to PPL Corporation Form 10-Q/A Report (File No. 1-11459) for the quarter ended June 30, 2011)
10(j)-9-Amendment No. 6, dated as of July 24, 2012, to said Credit and Security Agreement (Exhibit 10(a) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended September 30, 2012)
10(j)-10-Amendment No. 7, dated as of September 24, 2012, to said Credit and Security Agreement (Exhibit 10(b) to PPL Electric Utilities Corporation Form 10-Q Report (File No. 1-905) for the quarter ended September 30, 2012)
10(k)-1-Reimbursement Agreement, dated as of March 31, 2005, among PPL Energy Supply, LLC, The Bank of Nova Scotia, as Issuer and Administrative Agent, and the Lenders party thereto from time to time (Exhibit 10(a) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended March 31, 2005)
10(k)-2-First Amendment, dated as of June 16, 2005, to said Reimbursement Agreement (Exhibit 10(b) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended June 30, 2005)
10(k)-3-Second Amendment, dated as of September 1, 2005, to said Reimbursement Agreement (Exhibit 10(a) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended September 30, 2005)
10(k)-4-Third Amendment, dated as of March 30, 2006, to said Reimbursement Agreement (Exhibit 10(a) to PPL Energy Supply, LLC Form 8-K Report (File No. 333-74794) dated April 5, 2006)
10(k)-5-Fourth Amendment, dated as of April 12, 2006, to said Reimbursement Agreement (Exhibit 10(b) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended September 30, 2006)
10(k)-6-Fifth Amendment, dated as of November 1, 2006, to said Reimbursement Agreement (Exhibit 10(q)-6 to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2006)
10(k)-7-Sixth Amendment, dated as of March 29, 2007, to said Reimbursement Agreement (Exhibit 10(q)-7 to PPL Energy Supply, LLC Form 10-K Report (File No. 333-74794) for the year ended December 31, 2007)
10(k)-8-Seventh Amendment, dated as of March 1, 2008, to said Reimbursement Agreement (Exhibit 10(a) to PPL Energy Supply, LLC Form 10-Q Report (File No. 333-74794) for the quarter ended March 31, 2008)
424
10(k)-9-Eighth Amendment, dated as of March 30, 2009, to said Reimbursement Agreement (Exhibit 10(a) to PPL Energy Supply, LLC Form 10-Q Report (File No. 1-32944) for the quarter ended March 31, 2009)
10(k)-10-Ninth Amendment, dated as of March 31, 2010, to said Reimbursement Agreement (Exhibit 99.1Exhibit 10.1 to PPL Energy Supply, LLC Form 8-K Report (File No. 1-32944) dated April 6, 2010)June 12, 2014)
10(k)-1110.2-Tenth Amendment,Transition Services Agreement, dated as of February 22, 2012,June 1, 2015, by and between PPL Corporation and PPL Energy Supply, LLC (incorporated by reference to said ReimbursementExhibit 10.4 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
10.3-Transition Services Agreement, (Exhibit 10(k)-11dated as of May 4, 2015, by and between Topaz Power Management, LP and PPL Energy Supply, LLC (incorporated by reference to Exhibit 10.1 to PPL Energy Supply, LLC Form 10-K8-K Report (File No. 1-32944) for the year ended December 31, 2011)333-199888) filed on May 8, 2015)
*10(k)-12
10.4		-Eleventh Amendment, dated as of February 28, 2013, to said Reimbursement Agreement
10(l)-Purchase and SaleCredit Agreement, dated as of April 28, 2010,June 1, 2015, among PPL Energy Supply, LLC, the lenders and arrangers party thereto and Citibank, N.A., as administrative agent (incorporated by and between E.ON US Investments Corp., PPL Corporation and E.ON AG (Exhibit No. 99.1reference to PPLExhibit 10.1 to Talen Energy Corporation Form 8-K Report (File No. 1-11459) dated April 30, 2010)1-37388) filed on June 2, 2015)
10(m)10.5-$500 million FacilityGuarantee and Collateral Agreement, dated as of May 14, 2010,June 1, 2015, among PPL Energy Supply, LLC, the subsidiaries of the borrower from time to time party thereto and Citibank, N.A., as Borrower, and Morgan Stanley Bank, as Issuer (Exhibit 10(b)collateral trustee (incorporated by reference to PPLExhibit 10.2 to Talen Energy Supply, LLC Form 10-Q Report (File No. 1-32944) for the quarter ended June 30, 2010)
10(n)-Purchase and Sale Agreement, dated as of September 9, 2010, by and between PPL Holtwood, LLC and LSP Safe Harbor Holdings, LLC (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated September 13, 2010)1-37388) filed on June 2, 2015)
10(o)10.6-PurchaseCollateral Trust and SaleIntercreditor Agreement, dated as of September 9, 2010,June 1, 2015, among PPL Energy Supply, LLC, the subsidiary guarantors party thereto from time to time and Citibank, N.A., as administrative agent and as collateral trustee (incorporated by and between PPL Generation, LLC and Harbor Gen Holdings, LLC (Exhibit 10.2reference to PPLExhibit 10.3 to Talen Energy Corporation Form 8-K Report (File No. 1-11459) dated September 13, 2010)1-37388) filed on June 2, 2015)
10.7-Secured Energy Marketing and Trading Facility Common Agreement, dated as of November 1, 2010, among PPL EnergyPlus, LLC, PPL Energy Supply, LLC, PPL Brunner Island, LLC, PPL Montour, LLC, Wilmington Trust FSB, as Collateral Agent and the Secured Counterparties thereto (incorporated by reference to Exhibit 10.8 to Talen Energy Corporation Registration Statement on Form S-1 (File No. 333-199888) filed on March 18, 2015)
10(p)10.8-Open-End Mortgage, Security Agreement and Fixture Filing from PPL Montour, LLC to Wilmington Trust FSB, as Collateral Agent, dated as of October 26, 2010 (Exhibit(incorporated by reference to Exhibit 10(w) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
10(q)10.9-Open-End Mortgage, Security Agreement and Fixture Filing from PPL Brunner Island, LLC to Wilmington Trust FSB, as Collateral Agent, dated as of October 26, 2010 (Exhibit(incorporated by reference to Exhibit 10(x) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
10(r)10.10-Guaranty of PPL Montour, LLC and PPL Brunner Island, LLC, dated as of November 3, 2010, in favor of Wilmington Trust FSB, as Collateral Agent, for itself as Beneficiary and for the Secured Counterparties described therein (Exhibit(incorporated by reference to Exhibit 10(y) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
10(s)10.11-£300,000,000 Multicurrency Revolving CreditSecured Energy Marketing and Trading Facility Amended and Restated Common Agreement dated April 4, 2011,as of December 15, 2015 among Western Power Distribution (West Midlands) plc and Royal Bank of CanadaTalen Energy Marketing, LLC, Talen Energy Supply, LLC, Brunner Island, LLC, Montour, LLC, Wilmington Trust, National Association, as Lead Arranger, Bank of America Securities Limited as Bookrunner and Facility Agent, Bank of America, N.A. as Issuing Bankcollateral agent, and the other banks partysecured counterparties thereto as Mandated Lead Arrangers (Exhibit(incorporated by reference to Exhibit 10.1 to PPLTalen Energy Corporation Form 8-K Report (File No. 1-11459) dated April 8, 2011)1-37388) filed on December 21, 2015)
10(t)10.12-£300,000,000 Multicurrency Revolving Credit FacilityFirst Amendment to Collateral Trust and Intercreditor Agreement dated April 4, 2011,as of November 13, 2015 among Western Power Distribution (East Midlands) plcTalen Energy Supply, LLC, the subsidiary guarantors identified on the signature pages thereto and Royal Bank of CanadaCitibank, N.A., as Lead Arranger, Bank of America Securities Limited as Bookrunneradministrative agent and Facility Agent, Bank of America, N.A. as Issuing Bank and the other banks party thereto as Mandated Lead Arrangers (Exhibitcollateral trustee (incorporated by reference to Exhibit 10.2 to PPLTalen Energy Corporation Form 8-K Report (File No. 1-11459) dated April 8, 2011)1-37388) filed on December 21, 2015)
10(u)10.13-Amendment and RestatementAccession Agreement dated as of August 16, 2012, regarding $198,309,583.05 Amended and Restated Letter of Credit Agreement, dated as of August 16, 2012,December 15, 2015 among Kentucky Utilities Company,Wilmington Trust, National Association, the Lenders from time to time party hereto, and Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, as Administrative Agent (Exhibit 10(c) to Kentucky Utilities Company Form 10-Q Report (File No. 1-3464) forcredit parties identified on the quarter ended September 30, 2012)
425
10(v)-£245,000,000 Revolving Credit Facility Agreement, dated January 12, 2012, among Western Power Distribution (South West) plc, the lenders partysignature pages thereto and Lloyds TSB Bank Plc and Mizuho Corporate Bank, Ltd.Citibank, N.A, as Joint Coordinators (Exhibit 10.1collateral trustee, as acknowledged by Talen Energy Supply, LLC (incorporated by reference to PPLExhibit 10.2 to Talen Energy Corporation Form 8-K Report (File No. 1-11459) dated January 18, 2012)
10(w)-1-
Confirmation of Forward Sale Transaction, dated April 9, 2012, between PPL Corporation and Morgan Stanley & Co. LLC (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 13, 2012)
10(w)-2-Confirmation of Forward Sale Transaction, dated April 20, 2012, between PPL Corporation and Morgan Stanley & Co. LLC (Exhibit 10.1 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 26, 2012)
10(x)-1-Confirmation of Forward Sale Transaction, dated April 9, 2012, between PPL Corporation and Merrill Lynch International (Exhibit 10.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 13, 2012)
10(x)-2-Confirmation of Forward Sale Transaction, dated April 20, 2012, between PPL Corporation and Merrill Lynch International (Exhibit 10.2 to PPL Corporation Form 8-K Report (File No. 1-11459) dated April 26, 2012)
10(y)-Commitment Increase Agreement, dated as of April 20, 2012, entered into by and among PPL Electric Utilities Corporation, the Lenders who are increasing their Commitments, the JLA Issuing Banks, who are consenting to the increase in Fronting Sublimit, and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender (Exhibit 10(f) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2012)
10(z)-1-Uncommitted Line of Credit Letter Agreement, dated as of July 1, 2012, between PPL Energy Supply, LLC, the Borrower, and Banco Bilbao Vizcaya Argentaria, S.A., the Bank (Exhibit 10(b) to PPL Energy Supply, LLC Form 10-Q Report (File No. 1-32944) for the quarter ended June 30, 2012)
10(z)-2-Reimbursement Agreement, dated as of July 1, 2012, between PPL Energy Supply, LLC and Banco Bilbao Vizcaya Argentaria, S.A. (Exhibit 10(c) to PPL Energy Supply, LLC Form 10-Q Report (File No. 1-32944) for the quarter ended June 30, 2012)
10(aa)-Letter of Credit Issuance and Reimbursement Agreement, dated as of July 27, 2012, between PPL Energy Supply, LLC and Canadian Imperial Bank of Commerce, New York Agency (Exhibit 10(e) to PPL Energy Supply, LLC Form 10-Q Report (File No. 1-32944) for the quarter ended June 30, 2012)
*10(bb)
-$300,000,000 Amended and Restated Revolving Credit Agreement, dated as of November 6, 2012, among PPL Electric Utilities Corporation, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender
*10(cc)
-$3,000,000,000 Amended and Restated Revolving Credit Agreement, dated as of November 6, 2012, among PPL Energy Supply, LLC, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender
*10(dd)
-$400,000,000 Amended and Restated Revolving Credit Agreement, dated as of November 6, 2012, among Kentucky Utilities Company, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender
*10(ee)
-$500,000,000 Amended and Restated Revolving Credit Agreement, dated as of November 6, 2012, among Louisville Gas and Electric Company, the Lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender and Issuing Lender
1-37388) filed on December 21, 2015)

152

426
*10(ff)
-£210,000,000 Multicurrency Revolving Facility Agreement, dated December 21, 2012, among PPL WW Holdings Ltd., as the Company, Lloyds TSB Bank plc and Mizuho Corporate Bank, Ltd., as Joint Coordinators and Bookrunners, Barclays Bank PLC, Commonwealth Bank of Australia, HSBC Bank plc, Lloyds TSB Bank plc, Mizuho Corporate Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and The Royal Bank of Scotland plc, as Mandated Lead Arrangers and Mizuho Corporate Bank, Ltd., as Facility Agent
[_]10(gg)-110.14-Amended and Restated Directors Deferred Compensation Plan,Collateral Agency Agreement, dated Juneas of February 12, 2000 (Exhibit 10(h)2013, among PPL Ironwood, LLC, The Bank of New York Mellon, as Trustee, The Bank of New York Mellon, as Collateral Agent and The Bank of New York Mellon, as Depositary Bank (incorporated by reference to Exhibit 10(gg) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2000)2013)
[_]10(gg)-210.15*-Amendment No. 1 to said Directors Deferred Compensation Plan, dated December 18, 2002 (Exhibit 10(m)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002)
[_]10(gg)-3-Amendment No. 2 to said Directors Deferred Compensation Plan, dated December 4, 2003 (Exhibit 10(q)-2 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003)
[_]10(gg)-4-Amendment No. 3 to said Directors Deferred Compensation Plan, dated as of January 1, 2005 (Exhibit 10(cc)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2005)
[_]10(gg)-5-Amendment No. 4 to said Directors Deferred Compensation Plan, dated as of May 1, 2008 (Exhibit 10(x)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008)
[_]10(gg)-6-Amendment No. 5 to said Directors Deferred Compensation Plan, dated May 28, 2010 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2010)
*[_]10(hh)-1
-PPL Corporation Directors Deferred Compensation Plan TrustFirst Lien Credit and Guaranty Agreement, dated as of April 1, 2001, between PPL Corporation28, 2014, among New MACH Gen, LLC as borrower, the guarantors named therein, the lenders party thereto and Wachovia Bank, N.A. (as successorCLMG Corp., as administrative agent
10.16*`-First Amendment, dated as of March 30, 2015, to First Union National Bank), as Trustee
*[_]10(hh)-2
-PPL Officers Deferred Compensation Plan, PPL Supplemental Executive Retirement PlanLien Credit and PPL Supplemental Compensation Pension Plan TrustGuaranty Agreement, dated as of April 1, 2001, between PPL Corporation28, 2014, among New MACH Gen, LLC as borrower, the guarantors named therein, the lenders party thereto and Wachovia Bank, N.A. (as successor to First Union National Bank)CLMG Corp., as Trusteeadministrative agent
[_]10(hh)-310.17*-PPL Revocable Employee Nonqualified Plans TrustFirst Lien Security Agreement dated as of March 20, 2007,April 28, 2014 between PPL Corporationthe Grantors named therein and Wachovia Bank, N.A.CLMG Corp., as Trustee (Exhibit 10(c) to PPL Corporation Form 10-Q Report (File No. 1-1149) for the quarter ended March 31, 2007)First Lien Collateral Agent
[_]10(hh)-410.18*-PPL Employee Change in Control Agreements TrustCollateral Agency and Intercreditor Agreement dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A.April 28, 2014 among New MACH Gen, LLC, the guarantors party thereto, CLMG Corp., as Trustee (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)First Lien Administrative Agent, and CLMG Corp., as First Lien Collateral Agent
[_]10(hh)-510.19+-PPL Revocable Director Nonqualified Plans Trust Agreement, dated as of March 20, 2007, between PPL Corporation and Wachovia Bank, N.A., as Trustee (Exhibit 10(e)Talen Energy 2015 Stock Incentive Plan (incorporated by reference to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(ii)-1-Amended and Restated Officers Deferred Compensation Plan, dated December 8, 2003 (Exhibit 10(r)Exhibit 10.5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003)
[_]10(ii)-2-Amendment No. 1 to said Officers Deferred Compensation Plan, dated as of January 1, 2005 (Exhibit 10(ee)-1 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2005)
427
[_]10(ii)-3-Amendment No. 2 to said Officers Deferred Compensation Plan, dated as of January 22, 2007 (Exhibit 10(bb)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
[_]10(ii)-4-Amendment No. 3 to said Officers Deferred Compensation Plan, dated as of June 1, 2008 (Exhibit 10(z)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008)
[_]10(ii)-5-Amendment No. 4 to said Officers Deferred Compensation Plan, dated as of February 15, 2012 (Exhibit 10(ff)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2011)
[_]10(jj)-1-Amended and Restated Supplemental Executive Retirement Plan, dated December 8, 2003 (Exhibit 10(s) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2003)
[_]10(jj)-2-Amendment No. 1 to said Supplemental Executive Retirement Plan, dated December 16, 2004 (Exhibit 99.1 to PPLTalen Energy Corporation Form 8-K Report (File No. 1-11459) dated December 17, 2004)1-37388) filed on June 2, 2015)
[_]10(jj)-310.20+-Amendment No. 2 to said Supplemental Executive Retirement Plan, dated as of January 1, 2005 (Exhibit 10(ff)-3 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2005)
[_]10(jj)-4-Amendment No. 3 to said Supplemental Executive Retirement Plan, dated as of January 22, 2007 (Exhibit 10(cc)-4 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
[_]10(jj)-5-Amendment No. 4 to said Supplemental Executive Retirement Plan, dated as of December 9, 2008 (Exhibit 10(aa)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008)
[_]10(jj)-6-Amendment No. 5 to said Supplemental Executive Retirement Plan, dated as of February 15, 2012 (Exhibit 10(gg)-6 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2011)
[_]10(kk)-1-Amended and Restated IncentiveTalen Energy Directors Deferred Compensation Plan effective January 1, 2003 (Exhibit 10(p)(incorporated by reference to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002)
[_]10(kk)-2-Amendment No. 1Exhibit 10.6 to said Incentive Compensation Plan, dated as of January 1, 2005 (Exhibit 10(gg)-2 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2005)
[_]10(kk)-3-Amendment No. 2 to said Incentive Compensation Plan, dated as of January 26, 2007 (Exhibit 10(dd)-3 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
[_]10(kk)-4-Amendment No. 3 to said Incentive Compensation Plan, dated as of March 21, 2007 (Exhibit 10(f) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(kk)-5-Amendment No. 4 to said Incentive Compensation Plan, effective December 1, 2007 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended September 30, 2008)
[_]10(kk)-6-Amendment No. 5 to said Incentive Compensation Plan, dated as of December 16, 2008 (Exhibit 10(bb)-6 to PPL Corporation Form 10-K Report (File 1-11459) for the year ended December 31, 2008)
[_]10(kk)-7-Form of Stock Option Agreement for stock option awards under the Incentive Compensation Plan (Exhibit 10(a) to PPLTalen Energy Corporation Form 8-K Report (File No. 1-11459) dated February 1, 2006)1-37388) filed on June 2, 2015)
10.21+-Talen Energy Executive Deferred Compensation Plan (incorporated by reference to Exhibit 10.7 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
[_]10(kk)-810.22+-Talen Energy Supplemental Compensation Pension Plan (incorporated by reference to Exhibit 10.8 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
10.23+-Talen Energy Executive Severance Plan (incorporated by reference to Exhibit 10.9 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
10.24+-Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.10 to Talen Energy Corporation Form 8-K Report (File No. 1-37388) filed on June 2, 2015)
10.25+-Form of Restricted Stock Unit Agreement for restricted stock unit awards under the Incentive Compensation Plan (Exhibit 10(b)(incorporated by reference to PPLExhibit 10.11 to Talen Energy Corporation Form 8-K Report (File No. 1-11459) dated February 1, 2006)
428
1-37388) filed on June 2, 2015)
[_]10(kk)-910.26+-Form of Performance Unit Agreement for performance unit awards under the Incentive Compensation Plan (Exhibit 10(ss)(incorporated by reference to PPLExhibit 10.12 to Talen Energy Corporation Form 10-K8-K Report (File No. 1-11459) for the year ended December 31, 2007)1-37388) filed on June 2, 2015)
[_]10(ll)-110.27+-Amended and Restated Incentive Compensation PlanTalen Energy Form of Performance Unit Agreement for Key Employees, effective January 1, 2003 (Schedule BFiscal 2015 Awards (incorporated by reference to Proxy Statement of PPL Corporation, dated March 17, 2003)
[_]10(ll)-2-Exhibit 10.12 to Amendment No. 1 to said Incentive Compensation Plan for Key Employees, dated as of January 1, 2005 (Exhibit (hh)-1 to PPLTalen Energy Corporation Registration Statement on Form 10-K ReportS-1 (File 1-11459) for the year ended December 31, 2005)No. 333-207033) filed on October 29, 2015)
[_]10(ll)-310.28+-Talen Energy Short-Term Incentive Plan (incorporated by reference to Exhibit 10.18 to Amendment No. 21 to said Incentive Compensation Plan for Key Employees, dated as of January 26, 2007 (Exhibit 10(ee)-3 to PPL CorporationTalen Energy's Registration Statement on Form 10-K ReportS-1 (File No. 1-11459) for the year ended December 31, 2006)333-207033) filed on October 29, 2015)
[_]10(ll)-4-Amendment No. 3 to said Incentive Compensation Plan for Key Employees, dated as of March 21, 2007 (Exhibit 10(q) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(ll)-5-Amendment No. 4 to said Incentive Compensation Plan for Key Employees, dated as of December 15, 2008 (Exhibit 10(cc)-5 to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2008)
[_]10(ll)-6-Amendment No. 5 to said Incentive Compensation Plan for Key Employees, dated as of March 24, 2011 (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2011)
[_]10(mm)-Short-term Incentive Plan (Schedule A to Proxy Statement of PPL Corporation, dated April 6, 2011)
[_]10(nn)-Agreement, dated January 15, 2003, between PPL Corporation and Mr. Miller regarding Supplemental Pension Benefits (Exhibit 10(u) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2002)
[_]10(oo)-Employment letter, dated May 31, 2006, between PPL Services Corporation and William H. Spence (Exhibit 10(pp) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2006)
[_]10(pp)10.29+-Form of RetentionTalen Energy 2015 Stock Incentive Plan Restricted Stock Unit Agreement entered into between PPL Corporation and Messrs. DeCampli, Dudkin, Farr and Gabbard (Exhibit 10(h)(Matching Grants on Purchased Shares) (incorporated by reference to PPLExhibit 10.1 to Talen Energy Corporation Form 10-Q8-K Report (File No. 1-11459) for the quarter ended March 31, 2007)1-37388) filed on December 22, 2015)
[_]10(qq)-1
10.30+


-Form of Severance Agreement entered into between PPLTalen Energy Corporation and the Named Executive Officers (Exhibit 10(i) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2007)
[_]10(qq)-2-Amendment to said Severance Agreement (Exhibit 10(a) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2009)
[_]10(rr)-Amended and Restated Employment and Severance Agreement, dated as of October 29, 2010, between E.ON U.S. LLC and Victor A. Staffieri (Exhibit 10(ss) to PPL Corporation Form 10-K Report (File No. 1-11459) for the year ended December 31, 2010)
[_]10(ss)-1-Form of Change in Control Severance Protection Agreement as adopted March 5, 2012 (Exhibit 10(b)(incorporated by reference to PPLExhibit 10.1 to Talen Energy Corporation Form 10-Q8-K Report (File No. 1-11459) for the quarter ended March 31, 2012)1-37388) filed on December 29, 2015)
429
[_]10(ss)-212(a)*-
Form of Change in Control Severance Protection Agreement entered into between PPL Corporation and Messrs. Dudkin and Staffieri (Exhibit 10(c) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended March 31, 2012)
[_]10(tt)-1-PPL Corporation 2012 Stock Incentive Plan (Annex A to Proxy Statement of PPL Corporation, dated April 3, 2012)
*[_]10(tt)-2
-Form of Performance Unit Agreement for performance unit awards under the Stock Incentive Plan
*[_]10(tt)-3
-Form of Performance Contingent Restricted Stock Unit Agreement for restricted stock unit awards under the Stock Incentive Plan
*[_]10(tt)-4
-Form of Nonqualified Stock Option Agreement for stock option awards under the Stock Incentive Plan
[_]10(uu)-PPL Corporation Executive Severance Plan, effective as of July 26, 2012 (Exhibit 10(d) to PPL Corporation Form 10-Q Report (File No. 1-11459) for the quarter ended June 30, 2012)
*12(a)
-
PPL Talen Energy Corporation and Subsidiaries Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
12(b)*12(b)
-PPLTalen Energy Supply, LLC and Subsidiaries Computation of Ratio of Earnings to Fixed Charges
*12(c)
-PPL Electric Utilities Corporation and Subsidiaries Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
*12(d)
-LG&E and KU Energy LLC and Subsidiaries Computation of Ratio of Earnings to Fixed Charges
*12(e)
-Louisville Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges
*12(f)
-Kentucky Utilities Company Computation of Ratio of Earnings to Fixed Charges
*21
21*		-Subsidiaries of PPLTalen Energy Corporation
*23(a)
23*		-Consent of Ernst & Young LLP - PPLTalen Energy Corporation
24*-Power of Attorney

Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 for the period ended December 31, 2015 filed by the following officers for the following companies:
   
31(a)*23(b)
-Consent of Ernst & Young LLP Talen Energy Corporation's principal executive officer
31(b)*- PPLTalen Energy Corporation's principal financial officer
31(c)*-Talen Energy Supply, LLCLLC's principal executive officer
31(d)*-Talen Energy Supply, LLC's principal financial officer

153

Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 for the period ended December 31, 2015 furnished by the following officers for the following companies:
   
32(a)*23(c)
-Consent of Ernst & Young LLP - PPL Electric Utilities Corporation
*23(d)
-Consent of PricewaterhouseCoopers LLP - PPL Corporation
*23(e)
-Consent of Ernst & Young LLP - LG&E and KUTalen Energy LLC
*23(f)
-Consent of Ernst & Young LLP - Louisville Gas and Electric Company
*23(g)
-Consent of Ernst & Young LLP - Kentucky Utilities Company
*23(h)
-Consent of PricewaterhouseCoopers LLP - LG&E and KU Energy LLC
*23(i)
-Consent of PricewaterhouseCoopers LLP - Louisville Gas and Electric Company
*23(j)
-Consent of PricewaterhouseCoopers LLP - Kentucky Utilities Company
*24
-Power of Attorney
430
*31(a)
-
Certificate of PPL's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(b)
-Certificate of PPL's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(c)
-Certificate of PPL Energy Supply's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(d)
-Certificate of PPL Energy Supply's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(e)
-Certificate of PPL Electric's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(f)
-Certificate of PPL Electric's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(g)
-Certificate of LKE's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(h)
-Certificate of LKE's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(i)
-Certificate of LG&E's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(j)
-Certificate of LG&E's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(k)
-Certificate of KU's principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31(l)
-Certificate of KU's principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32(a)
-
Certificate of PPL's principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32(b)
-Certificate of PPL Energy Supply'sCorporation's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32(b)*32(c)
-Certificate of PPL Electric'sTalen Energy Supply, LLC's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32(d)
-Certificate of LKE's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32(e)
-Certificate of LG&E's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32(f)
-Certificate of KU's principal executive officer and principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS-XBRL Instance Document for PPLTalen Energy Corporation PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
431
101.SCH-XBRL Taxonomy Extension Schema for PPLTalen Energy Corporation PPL Corporation, PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
101.CAL-XBRL Taxonomy Extension Calculation Linkbase for PPLTalen Energy Corporation PPL Corporation, PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
101.DEF-XBRL Taxonomy Extension Definition Linkbase for PPLTalen Energy Corporation PPL Corporation, PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
101.LAB-XBRL Taxonomy Extension Label Linkbase for PPLTalen Energy Corporation PPL Corporation, PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
101.PRE-XBRL Taxonomy Extension Presentation Linkbase for PPLTalen Energy Corporation PPL Corporation, PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company

432



154