UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

 

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2015March 31, 2016

or

 

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission

File Number

  

Name of Registrant; State or Other Jurisdiction of Incorporation;

Address
of Principal Executive Offices; and

Telephone Number

  IRS Employer
Identification
Number
 

1-16169

  

EXELON CORPORATION

   23-2990190  
  

(a Pennsylvania corporation)

10 South Dearborn Street

P.O. Box 805379

Chicago, Illinois 60680-5379

(800) 483-3220

  

333-85496

  

EXELON GENERATION COMPANY, LLC

   23-3064219  
  

(a Pennsylvania limited liability company)

300 Exelon Way

Kennett Square, Pennsylvania 19348-2473

(610) 765-5959

  

1-1839

  

COMMONWEALTH EDISON COMPANY

   36-0938600  
  

(an Illinois corporation)

440 South LaSalle Street

Chicago, Illinois 60605-1028

(312) 394-4321

  

000-16844

  

PECO ENERGY COMPANY

   23-0970240  
  

(a Pennsylvania corporation)

P.O. Box 8699

2301 Market Street

Philadelphia, Pennsylvania 19101-8699

(215) 841-4000

  

1-1910

  

BALTIMORE GAS AND ELECTRIC COMPANY

   52-0280210  
  

(a Maryland corporation)

2 Center Plaza

110 West Fayette Street

Baltimore, Maryland 21201-3708

(410) 234-5000

  

001-31403

PEPCO HOLDINGS LLC

52-2297449

(a Delaware limited liability company)

701 Ninth Street, N.W.

Washington, District of Columbia 20068

(202) 872-2000

001-01072

POTOMAC ELECTRIC POWER COMPANY

53-0127880

(a District of Columbia and Virginia corporation)

701 Ninth Street, N.W.

Washington, District of Columbia 20068

(202) 872-2000

001-01405

DELMARVA POWER & LIGHT COMPANY

(a Delaware and Virginia corporation)

500 North Wakefield Drive

Newark, Delaware 19702

(202) 872-2000

51-0084283

001-03559

ATLANTIC CITY ELECTRIC COMPANY

21-0398280

(a New Jersey corporation)

500 North Wakefield Drive

Newark, Delaware 19702

(202) 872-2000


Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

   Large Accelerated Filer  Accelerated Filer  Non-accelerated Filer  Smaller
Reporting
Company

Exelon Corporation

  x      

Exelon Generation Company, LLC

      x  

Commonwealth Edison Company

      x  

PECO Energy Company

      x  

Baltimore Gas and Electric Company

      x  

Pepco Holdings LLC

x

Potomac Electric Power Company

x

Delmarva Power & Light Company

x

Atlantic City Electric Company

x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The number of shares outstanding of each registrant’s common stock as of September 30, 2015March 31, 2016 was:

 

Exelon Corporation Common Stock, without par value

  919,564,380887,313,966

Exelon Generation Company, LLC

  not applicable

Commonwealth Edison Company Common Stock, $12.50 par value

  127,016,973127,017,042

PECO Energy Company Common Stock, without par value

  170,478,507

Baltimore Gas and Electric Company Common Stock, without par value

  1,000

Pepco Holdings LLC

not applicable

Potomac Electric Power Company Common Stock, $.01 par value

100

Delmarva Power & Light Company Common Stock, $2.25 par value

1,000

Atlantic City Electric Company Common Stock, $3.00 par value

8,546,017


TABLE OF CONTENTS

 

  Page No. 
FILING FORMAT  79  
FORWARD-LOOKING STATEMENTS  79  
WHERE TO FIND MORE INFORMATION  79  
PART I. 

FINANCIAL INFORMATION

  810  
ITEM 1. 

FINANCIAL STATEMENTS

  810  
 

Exelon Corporation

 
 

Consolidated Statements of Operations and Comprehensive Income

  911  
 

Consolidated Statements of Cash Flows

  1012  
 

Consolidated Balance Sheets

  1113  
 

Consolidated Statement of Changes in Shareholders’ Equity

  1315  
 

Exelon Generation Company, LLC

 
 

Consolidated Statements of Operations and Comprehensive Income

  1416  
 

Consolidated Statements of Cash Flows

  1517  
 

Consolidated Balance Sheets

  1618  
 

Consolidated Statement of Changes in Equity

  1820  
 

Commonwealth Edison Company

 
 

Consolidated Statements of Operations and Comprehensive Income

  1921  
 

Consolidated Statements of Cash Flows

  2022  
 

Consolidated Balance Sheets

  2123  
 

Consolidated Statement of Changes in Shareholders’ Equity

  2325  
 

PECO Energy Company

 
 

Consolidated Statements of Operations and Comprehensive Income

  2426  
 

Consolidated Statements of Cash Flows

  2527  
 

Consolidated Balance Sheets

  2628  
 

Consolidated Statement of Changes in Shareholders’Shareholder’s Equity

  2830  
 

Baltimore Gas and Electric Company

 
 

Consolidated Statements of Operations and Comprehensive Income

  2931  
 

Consolidated Statements of Cash Flows

  3032  
 

Consolidated Balance Sheets

  3133  
 

Consolidated Statement of Changes in Shareholders’ Equity

  3335  
 

Pepco Holdings LLC

Combined Notes to Consolidated Financial Statements of Operations and Comprehensive Income

  3436  
 

1. BasisConsolidated Statements of PresentationCash Flows

  3437  
 

2. New Accounting Pronouncements

35

3. Variable Interest EntitiesConsolidated Balance Sheets

  38  
 

4. Mergers, Acquisitions and DispositionsConsolidated Statement of Changes in Equity

  44

5. Regulatory Matters

47

6. Investment in Constellation Energy Nuclear Group, LLC

6040  

  Page No. 
 

Potomac Electric Power Company

7. ImpairmentStatements of Long-Lived AssetsOperations and Comprehensive Income

  6141

Statements of Cash Flows

42

Balance Sheets

43

Statement of Changes in Shareholder’s Equity

45

Delmarva Power & Light Company

Statements of Operations and Comprehensive Income

46

Statements of Cash Flows

47

Balance Sheets

48

Statement of Changes in Shareholder’s Equity

50

Atlantic City Electric Company

Consolidated Statements of Operations and Comprehensive Income

51

Consolidated Statements of Cash Flows

52

Consolidated Balance Sheets

53

Consolidated Statement of Changes in Shareholder’s Equity

55

Combined Notes to Consolidated Financial Statements

56

1. Significant Accounting Policies (All Registrants)

56

2. New Accounting Pronouncements (All Registrants)

59

3. Variable Interest Entities (All Registrants)

62

4. Mergers, Acquisitions and Dispositions

69

5. Regulatory Matters (All Registrants)

75

6. Impairment of Long-Lived Assets (Exelon and Generation)

89

7. Implications of Potential Early Plant Retirements (Exelon and Generation)

90  
 

8. ImplicationsFair Value of Potential Early Plant RetirementsFinancial Assets and Liabilities (All Registrants)

  6391  
 

9. Fair Value ofDerivative Financial Assets and LiabilitiesInstruments (All Registrants)

  64113  
 

10. Derivative Financial InstrumentsDebt and Credit Agreements (All Registrants)

  82130  
 

11. Debt and Credit AgreementsIncome Taxes (All Registrants)

  99134  
 

12. Income TaxesNuclear Decommissioning (Exelon and Generation)

  105138  
 

13. Nuclear DecommissioningRetirement Benefits (All Registrants)

  109141  
 

14. Retirement BenefitsSeverance (All Registrants)

  112143  
 

15. SeveranceChanges in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)

  114146  
 

16. Changes in Accumulated Other Comprehensive IncomeMezzanine Equity (Exelon, Generation and PHI)

  115149  
 

17. Common StockEarnings Per Share (Exelon)

  120150  
 

18. Earnings Per ShareCommitments and EquityContingencies (All Registrants)

  120151  
 

19. Commitments and ContingenciesSupplemental Financial Information (All Registrants)

  121165  
 

20. Supplemental FinancialSegment Information (All Registrants)

  132172  

 

21. Segment InformationPage No.

138 
ITEM 2. 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

  143178  
 

Exelon Corporation

  143178  
 

General

  143178  
 

Executive Overview

  144179  
 

Critical Accounting Policies and Estimates

  171195  
 

Results of Operations

  172195  
 

Liquidity and Capital Resources

  200237  
 

Contractual Obligations and Off-Balance Sheet Arrangements

  210250  
ITEM 3. 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  212251  
ITEM 4. 

CONTROLS AND PROCEDURES

  220261  
PART II. 

OTHER INFORMATION

  222262  
ITEM 1. 

LEGAL PROCEEDINGS

  222262  
ITEM 1A. 

RISK FACTORS

  222262  
ITEM 4. 

MINE SAFETY DISCLOSURES

  222263  
ITEM 6. 

EXHIBITS

  222263  
SIGNATURES  224266  
 

Exelon Corporation

  224266  
 

Exelon Generation Company, LLC

  224266  
 

Commonwealth Edison Company

  225266  
 

PECO Energy Company

  225267  
 

Baltimore Gas and Electric Company

  225267

Pepco Holdings LLC

267

Potomac Electric Power Company

268

Delmarva Power & Light Company

268

Atlantic City Electric Company

268  

GLOSSARY OF TERMS AND ABBREVIATIONS

Exelon Corporation and Related Entities

Exelon

  

Exelon Corporation

Generation

  

Exelon Generation Company, LLC

ComEd

  

Commonwealth Edison Company

PECO

  

PECO Energy Company

BGE

  

Baltimore Gas and Electric Company

Pepco Holdings or PHI

Pepco Holdings LLC (formerly Pepco Holdings, Inc.)

Pepco

Potomac Electric Power Company

Pepco Energy Services or PES

Pepco Energy Services, Inc. and its subsidiaries

PCI

Potomac Capital Investment Corporation and its subsidiaries

DPL

Delmarva Power & Light Company

ACE

Atlantic City Electric Company

ACE Funding or ATF

Atlantic City Electric Transition Funding LLC

BSC

  

Exelon Business Services Company, LLC

PHISCO

PHI Service Company

Exelon Corporate

  

Exelon’sExelon in its corporate capacity as a holding company

PHI Corporate

PHI in its corporate capacity as a holding company

CENG

  

Constellation Energy Nuclear Group, LLC

Constellation

  

Constellation Energy Group, Inc.

Antelope Valley AVSR

  

Antelope Valley Solar Ranch One

Exelon Transmission Company

  

Exelon Transmission Company, LLC

Exelon Wind

  

Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC

Ventures

  

Exelon Ventures Company, LLC

AmerGen

  

AmerGen Energy Company, LLC

BondCo

  

RSB BondCo LLC

ComEd Financing III

ComEd Financing III

PEC L.P.

  

PECO Energy Capital, L.P.

PECO Trust III

  

PECO Energy Capital Trust III

PECO Trust IV

  

PECO Energy Capital Trust IV

BGE Trust II

BGE Capital Trust II

PETT

  

PECO Energy Transition Trust

Registrants

  

Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively

Utility Registrants

ComEd, PECO, BGE, Pepco, DPL and ACE, collectively

Legacy PHI

PHI, Pepco, DPL and ACE, collectively

 

Other Terms and Abbreviations

Note “—” of the Exelon 20142015 Form 10-K

  Reference to a specific Combined Note to Consolidated Financial Statements within Exelon’s 20142015 Annual Report on Form 10-K

Note “—” of the PHI 2015 Form 10-K

Reference to specific Note to Consolidated Financial Statements within Legacy PHI’s 2015 Annual Report on Form 10-K

1998 restructuring settlement

  PECO’s 1998 settlement of its restructuring case mandated by the Competition Act

Act 11

  Pennsylvania Act 11 of 2012

Act 129

  Pennsylvania Act 129 of 2008

AEC

  Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source

AEPS

  Pennsylvania Alternative Energy Portfolio Standards

AEPS Act

  Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended

AESO

  Alberta Electric Systems Operator

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

AFUDC

  Allowance for Funds Used During Construction

ALJ

  Administrative Law Judge

AMI

  Advanced Metering Infrastructure

AMP

  Advanced Metering Program

ARC

  Asset Retirement Cost

ARO

  Asset Retirement Obligation

ARP

  Title IV Acid Rain Program

ARRA of 2009

  American Recovery and Reinvestment Act of 2009

ASC

Accounting Standards Codification

BGS

Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)

Block contracts

  Forward Purchase Energy Block Contracts

CAIR

  Clean Air Interstate Rule

CAISO

  California ISO

CAMR

  Federal Clean Air Mercury Rule

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

CERCLA

  Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended

CFL

  Compact Fluorescent Light

Clean Air Act

  Clean Air Act of 1963, as amended

Clean Water Act

  Federal Water Pollution Control Amendments of 1972, as amended

Competition Act

  Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996

Conectiv

Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE

Conectiv Energy

Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010

Contract EDCs

Pepco, DPL and BGE, the Maryland utilities required by the MDPSC to enter into a contract for new generation

CPI

  Consumer Price Index

CPUC

  California Public Utilities Commission

CSAPR

  Cross-State Air Pollution Rule

CTA

Consolidated tax adjustment

CTC

  Competitive Transition Charge

DCD.C. Circuit Court

  United States Court of Appeals for the District of Columbia Circuit

DCPSC

District of Columbia Public Service Commission

DC PLUG

District of Columbia Power Line Undergrounding

Default Electricity Supply

The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS

Default Electricity Supply Revenue

Revenue primarily from Default Electricity Supply

DOE

  United States Department of Energy

DOJ

  United States Department of Justice

DPSC

Delaware Public Service Commission

DRP

Direct Stock Purchase and Dividend Reinvestment Plan

DSP

  Default Service Provider

DSP Program

  Default Service Provider Program

EDCs

Electric distribution companies

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

EDF

  Electricite de France SA and its subsidiaries

EE&C

  Energy Efficiency and Conservation/Demand Response

EGR

ExGen Renewables I, LLC

EGS

  Electric Generation Supplier

EGTP

  ExGen Texas Power, LLC

EIMA

  Illinois Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)

EmPower Maryland

A Maryland demand-side management program for Pepco and DPL

EPA

  United States Environmental Protection Agency

ERCOT

  Electric Reliability Council of Texas

ERISA

  Employee Retirement Income Security Act of 1974, as amended

EROA

  Expected Rate of Return on Assets

ESPP

  Employee Stock Purchase Plan

FASB

  Financial Accounting Standards Board

FERC

  Federal Energy Regulatory Commission

FRCC

  Florida Reliability Coordinating Council

FTC

  Federal Trade Commission

GAAP

  Generally Accepted Accounting Principles in the United States

GDPGCR

  Gross Domestic ProductGas Cost Rate

GHG

  Greenhouse Gas

GRT

  Gross Receipts Tax

GSA

  Generation Supply Adjustment

GWh

  Gigawatt hour

HAP

  Hazardous air pollutants

Health Care Reform Acts

  Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010

HSR Act

The Hart-Scott-Rodino Antitrust Improvements Act of 1976

IBEW

  International Brotherhood of Electrical Workers

ICC

  Illinois Commerce Commission

ICE

  Intercontinental Exchange

Illinois Act

  Illinois Electric Service Customer Choice and Rate Relief Law of 1997

Illinois EPA

  Illinois Environmental Protection Agency

Illinois Settlement Legislation

  Legislation enacted in 2007 affecting electric utilities in Illinois

Integrys

  Integrys Energy Services, Inc.

IPA

  Illinois Power Agency

IRC

  Internal Revenue Code

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

IRS

  Internal Revenue Service

ISO

  Independent System Operator

ISO-NE

  ISO New England Inc.

ISO-NY

  ISO New York Independent System Operator

kV

  Kilovolt

kW

  Kilowatt

kWh

  Kilowatt-hour

LIBOR

  London Interbank Offered Rate

LILO

  Lease-In, Lease-Out

LLRW

  Low-Level Radioactive Waste

LTIP

  Long-Term Incentive Plan

MAPP

Mid-Atlantic Power Pathway

MATS

  U.S. EPA Mercury and Air Toxics Standard Rule

MBR

  Market Based Rates Incentive

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

MDE

  Maryland Department of the Environment

MDPSC

  Maryland Public Service Commission

MGP

  Manufactured Gas Plant

MISO

  Midcontinent Independent System Operator, Inc.

mmcf

  Million Cubic Feet

Moody’s

  Moody’s Investor Service

MOPR

  Minimum Offer Price Rule

MRV

  Market-Related Value

MW

  Megawatt

MWh

  Megawatt hour

NAAQS

  National Ambient Air Quality Standards

n.m.

  not meaningful

NAV

  Net Asset Value

NDT

  Nuclear Decommissioning Trust

NEIL

  Nuclear Electric Insurance Limited

NERC

  North American Electric Reliability Corporation

NGS

  Natural Gas Supplier

NJBPU

New Jersey Board of Public Utilities

NJDEP

  New Jersey Department of Environmental Protection

Non-Regulatory Agreements Units

  Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting including the CENG units (Calvert Cliffs, Nine Mile Point, and R.E. Ginna), Clinton, Oyster Creek, Three Mile Island, Zion (a former ComEd unit), and portions of Peach Bottom (a former PECO unit)

NOSA

  Nuclear Operating Services Agreement

NOV

  Notice of Violation

NPDES

  National Pollutant Discharge Elimination System

NRC

  Nuclear Regulatory Commission

NSPS

  New Source Performance Standards

NUGs

Non-utility generators

NWPA

  Nuclear Waste Policy Act of 1982

NYMEX

  New York Mercantile Exchange

OCI

  Other Comprehensive Income

OIESO

  Ontario Independent Electricity System Operator

OPC

Office of People’s Counsel

OPEB

  Other Postretirement Employee Benefits

PA DEP

  Pennsylvania Department of Environmental Protection

PAPUC

  Pennsylvania Public Utility Commission

PGC

  Purchased Gas Cost Clause

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

PHI Retirement Plan

  Pepco Holdings, Inc.PHI’s noncontributory retirement plan

PJM

  PJM Interconnection, LLC

POLR

  Provider of Last Resort

POR

  Purchase of Receivables

PPA

  Power Purchase Agreement

PPL

PPL Holtwood, LLC

Price-Anderson Act

  Price-Anderson Nuclear Industries Indemnity Act of 1957

Preferred Stock

Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share

PRP

  Potentially Responsible Parties

PSEG

  Public Service Enterprise Group Incorporated

PURTA

  Pennsylvania Public Realty Tax Act

PV

  Photovoltaic

GLOSSARY OF TERMS AND ABBREVIATIONS

Other Terms and Abbreviations

RCRA

  Resource Conservation and Recovery Act of 1976, as amended

REC

  Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

Regulatory Agreement Units

  Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting including the former ComEd units (Braidwood, Bryon, Dresden, LaSalle, Quad Cities) and the former PECO units (Limerick, Peach Bottom, Salem)

RES

  Retail Electric Suppliers

RFP

  Request for Proposal

Rider

  Reconcilable Surcharge Recovery Mechanism

RGGI

  Regional Greenhouse Gas Initiative

RMC

  Risk Management Committee

ROE

  Return on Common Equityequity

RPM

  PJM Reliability Pricing Model

RPS

  Renewable Energy Portfolio Standards

RTEP

  Regional Transmission Expansion Plan

RTO

  Regional Transmission Organization

S&P

  Standard & Poor’s Ratings Services

SEC

  United States Securities and Exchange Commission

Senate Bill 1

  Maryland Senate Bill 1

SERC

  SERC Reliability Corporation (formerly Southeast Electric Reliability Council)

SERP

  Supplemental Employee Retirement Plan

SGIG

  Smart Grid Investment Grant

SGIP

  Smart Grid Initiative Program

SILO

  Sale-In, Lease-Out

SMP

Smart Meter Program

SMPIP

  Smart Meter Procurement and Installation Plan

SNF

  Spent Nuclear Fuel

SOASOCAs

  SocietyStandard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of Actuariesqualified electric generation facilities in New Jersey

SOS

  Standard Offer Service

SPP

  Southwest Power Pool

Tax Relief Act of 2010

  Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010

Transition Bond Charge

Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees

Transition Bonds

Transition Bonds issued by ACE Funding

Upstream

  Natural gas and oil exploration and production activities

VIE

  Variable Interest Entity

WECC

  Western Electric Coordinating Council

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, and Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

FORWARD-LOOKING STATEMENTS

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) Exelon’s 20142015 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 22;23; (2) PHI’s 2015 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 16; (3) this Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors, (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 19;18; and (3)(4) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the SEC atwww.sec.gov and the Registrants’ websites atwww.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.

 

PART I. FINANCIAL INFORMATION

Item 1.    Financial Statements

 

 

 

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions, except per share data)      2015         2014     2015 2014       2016         2015     

Operating revenues

  $7,401   $6,912   $22,746   $20,173     

Competitive businesses revenues

  $4,473   $5,632  

Rate-regulated utility revenues

   3,100    3,198  
  

 

  

 

 

Total operating revenues

   7,573    8,830  

Operating expenses

        

Purchased power and fuel

   3,291    2,591    10,210    8,943  

Purchased power and fuel from affiliates

       57        456  

Competitive businesses purchased power and fuel

   2,440    3,426  

Rate-regulated utility purchased power and fuel

   814    1,044  

Operating and maintenance

   1,996    1,982    6,119    6,005     2,835    2,081  

Depreciation and amortization

   606    577    1,818    1,732     685    610  

Taxes other than income

   310    306    908    887     325    304  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating expenses

   6,203    5,513    19,055    18,023     7,099    7,465  
  

 

  

 

  

 

  

 

   

 

  

 

 

Equity in losses of unconsolidated affiliates

               (20

Gain on sales of assets

   2    339    10    356     9    1  

Gain on consolidation and acquisition of businesses

               261  
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating income

   1,200    1,738    3,701    2,747     483    1,366  
  

 

  

 

  

 

  

 

   

 

  

 

 

Other income and (deductions)

        

Interest expense, net

   (243  (247  (724  (691   (277  (335

Interest expense to affiliates

   (10  (11  (31  (31

Interest expense to affiliates, net

   (10  (10

Other, net

   (244  16    (179  346     114    80  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total other income and (deductions)

   (497  (242  (934  (376   (173  (265
  

 

  

 

  

 

  

 

   

 

  

 

 

Income before income taxes

   703    1,496    2,767    2,371     310    1,101  

Income taxes

   115    422    805    646     184    363  

Equity in losses of unconsolidated affiliates

   (1      (3       (3    
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income

   587    1,074    1,959    1,725     123    738  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income (loss) attributable to noncontrolling interest and preference stock dividends

   (42  81        121  

Net (loss) income attributable to noncontrolling interest and preference stock dividends

   (50  45  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income attributable to common shareholders

  $629   $993   $1,959   $1,604    $173   $693  
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income, net of income taxes

        

Net income

  $587   $1,074   $1,959   $1,725    $123   $738  

Other comprehensive income (loss), net of income taxes

        

Pension and non-pension postretirement benefit plans:

        

Prior service benefit reclassified to periodic benefit cost

   (11  (11  (35  (18   (12  (11

Actuarial loss reclassified to periodic cost

   55    38    165    109  

Pension and non-pension postretirement benefit plans valuation adjustment

       (8  (29  240  

Unrealized gain (loss) on cash flow hedges

   (3  (19  4    (92

Unrealized gain (loss) on equity investments

       (3      8  

Actuarial loss reclassified to periodic benefit cost

   46    54  

Pension and non-pension postretirement benefit plan valuation adjustment

   (1  (26

Unrealized (loss) gain on cash flow hedges

   (7  6  

Unrealized loss on equity investments

   (3    

Unrealized gain (loss) on foreign currency translation

   (8  (5  (17  (6   6    (12

Unrealized loss on marketable securities

   (1  (3      (2   (1    

Reversal of CENG equity method AOCI

               (116
  

 

  

 

  

 

  

 

   

 

  

 

 

Other comprehensive income (loss)

   32    (11  88    123  

Other comprehensive income

   28    11  
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income

  $619   $1,063   $2,047   $1,848    $151   $749  
  

 

  

 

  

 

  

 

   

 

  

 

 

Average shares of common stock outstanding:

        

Basic

   913    861    879    860     923    862  

Diluted

   915    863    883    863     925    867  
  

 

  

 

  

 

  

 

 

Earnings per average common share:

        

Basic

  $0.69   $1.15   $2.23   $1.87    $0.19   $0.80  

Diluted

  $0.69   $1.15   $2.22   $1.86    $0.19   $0.80  
  

 

  

 

  

 

  

 

   

 

  

 

 

Dividends per common share

  $0.31   $0.31   $0.93   $0.93    $0.31   $0.31  
  

 

  

 

  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)  2015 2014       2016         2015     

Cash flows from operating activities

      

Net income

  $1,959   $1,725    $123   $738  

Adjustments to reconcile net income to net cash flows provided by operating activities:

      

Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization

   2,930    2,856     1,063    948  

Impairment of long-lived assets

   25    162     119      

Gain on consolidation and acquisition of businesses

       (268

Gain on sales of assets

   (10  (356   (9  (1

Deferred income taxes and amortization of investment tax credits

   241    459     127    129  

Net fair value changes related to derivatives

   (363  522     (107  (91

Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments

   221    (141

Net realized and unrealized gains on nuclear decommissioning trust fund investments

   (55  (47

Other non-cash operating activities

   856    698     804    344  

Changes in assets and liabilities:

      

Accounts receivable

   175    198     117    (270

Inventories

   65    (316   142    291  

Accounts payable, accrued expenses and other current liabilities

   (147  (322

Accounts payable and accrued expenses

   (571  (468

Option premiums received, net

   27    21     17    5  

Counterparty collateral received (posted), net

   305    (615

Collateral received, net

   206    257  

Income taxes

   300    72     47    174  

Pension and non-pension postretirement benefit contributions

   (430  (516   (239  (269

Other assets and liabilities

   (480  (536   (311  (250
  

 

  

 

   

 

  

 

 

Net cash flows provided by operating activities

   5,674    3,643     1,473    1,490  
  

 

  

 

   

 

  

 

 

Cash flows from investing activities

      

Capital expenditures

   (5,443  (4,114   (2,202  (1,784

Proceeds from nuclear decommissioning trust fund sales

   4,551    5,464     2,240    1,681  

Investment in nuclear decommissioning trust funds

   (4,737  (5,550   (2,297  (1,747

Acquisition of businesses

   (28  (67

Acquisition of businesses, net of cash acquired

   (6,645  (15

Proceeds from sale of long-lived assets

   145    660         142  

Proceeds from termination of direct financing lease investment

       335     360      

Proceeds from sales of investments

       7  

Cash and restricted cash acquired from consolidations and acquisitions

       129  

Change in restricted cash

   (70  (151   (2  (26

Other investing activities

   (107  (89   (2  (2
  

 

  

 

   

 

  

 

 

Net cash flows used in investing activities

   (5,689  (3,376   (8,548  (1,751
  

 

  

 

   

 

  

 

 

Cash flows from financing activities

      

Changes in short-term borrowings

   230    236     1,647    (141

Proceeds from short-term borrowings with maturities greater than 90 days

   123      

Issuance of long-term debt

   5,909    3,212     151    1,206  

Retirement of long-term debt

   (1,745  (1,214   (116  (580

Issuance of common stock

   1,868      

Distributions to noncontrolling interest of consolidated VIE

       (415

Dividends paid on common stock

   (819  (799   (287  (269

Proceeds from employee stock plans

   24    25     9    8  

Other financing activities

   (65  (158   6    (16
  

 

  

 

   

 

  

 

 

Net cash flows provided by financing activities

   5,402    887     1,533    208  
  

 

  

 

   

 

  

 

 

Increase in cash and cash equivalents

   5,387    1,154  

Decrease in cash and cash equivalents

   (5,542  (53

Cash and cash equivalents at beginning of period

   1,878    1,609     6,502    1,878  
  

 

  

 

   

 

  

 

 

Cash and cash equivalents at end of period

  $7,265   $2,763    $960   $1,825  
  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
ASSETS        

Current assets

        

Cash and cash equivalents

  $7,265    $1,878    $960    $6,502  

Restricted cash and cash equivalents

   341     271     218     205  

Accounts receivable, net

        

Customer

   3,215     3,482     3,594     3,187  

Other

   1,107     1,227     1,138     912  

Mark-to-market derivative assets

   1,116     1,279     1,185     1,365  

Unamortized energy contract assets

   135     254     85     86  

Inventories, net

        

Fossil fuel and emission allowances

   442     579     285     462  

Materials and supplies

   1,074     1,024     1,229     1,104  

Deferred income taxes

   211     244  

Regulatory assets

   779     847     1,584     759  

Assets held for sale

   4     147  

Other

   1,178     865     1,086     752  
  

 

   

 

   

 

   

 

 

Total current assets

   16,867     12,097     11,364     15,334  
  

 

   

 

   

 

   

 

 

Property, plant and equipment, net

   55,814     52,087     69,406     57,439  

Deferred debits and other assets

        

Regulatory assets

   6,000     6,076     10,407     6,065  

Nuclear decommissioning trust funds

   10,103     10,537     10,526     10,342  

Investments

   620     544     455     639  

Goodwill

   2,672     2,672     6,688     2,672  

Mark-to-market derivative assets

   801     773     841     758  

Deferred income taxes

   2       

Unamortized energy contracts assets

   513     549     474     484  

Pledged assets for Zion Station decommissioning

   237     319     183     206  

Other

   1,499     1,160     1,398     1,445  
  

 

   

 

   

 

   

 

 

Total deferred debits and other assets

   22,447     22,630     30,972     22,611  
  

 

   

 

   

 

   

 

 

Total assets(a)

  $95,128    $86,814    $111,742    $95,384  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
 December 31,
2014
  March 31,
2016
 December 31,
2015
 
  (Unaudited)    (Unaudited)   
LIABILITIES AND SHAREHOLDERS’ EQUITY     

Current liabilities

     

Short-term borrowings

  $675   $460   $3,640   $533  

Long-term debt due within one year

   897    1,802    2,058    1,500  

Accounts payable

   2,987    3,048    2,874    2,883  

Accrued expenses

   1,576    1,539    2,260    2,376  

Payables to affiliates

   8    8    8    8  

Regulatory liabilities

   365    310    512    369  

Mark-to-market derivative liabilities

   204    234    203    205  

Unamortized energy contract liabilities

   118    238    582    100  

Renewable energy credit obligation

  308    302  

PHI merger related obligation

  317      

Other

   1,017    1,123    1,008    842  
  

 

  

 

  

 

  

 

 

Total current liabilities

   7,847    8,762    13,770    9,118  
  

 

  

 

  

 

  

 

 

Long-term debt

   24,541    19,362    29,314    23,645  

Long-term debt to financing trusts

   648    648    641    641  

Deferred credits and other liabilities

     

Deferred income taxes and unamortized investment tax credits

   13,480    13,019    17,474    13,776  

Asset retirement obligations

   8,405    7,295    8,755    8,585  

Pension obligations

   3,014    3,366    3,771    3,385  

Non-pension postretirement benefit obligations

   1,877    1,742    1,902    1,618  

Spent nuclear fuel obligation

   1,021    1,021    1,022    1,021  

Regulatory liabilities

   4,180    4,550    4,378    4,201  

Mark-to-market derivative liabilities

   360    403    408    374  

Unamortized energy contract liabilities

   136    211    1,144    117  

Payable for Zion Station decommissioning

   99    155    72    90  

Other

   2,231    2,147    1,886    1,491  
  

 

  

 

  

 

  

 

 

Total deferred credits and other liabilities

   34,803    33,909    40,812    34,658  
  

 

  

 

  

 

  

 

 

Total liabilities(a)

   67,839    62,681    84,537    68,062  
  

 

  

 

  

 

  

 

 

Commitments and contingencies

     

Contingently redeemable noncontrolling interest

  19    28  

Shareholders’ equity

     

Common stock (No par value, 2,000 shares authorized, 920 shares and 860 shares outstanding at September 30, 2015 and December 31, 2014, respectively)

   18,647    16,709  

Treasury stock, at cost (35 shares at both September 30, 2015 and December 31, 2014)

   (2,327  (2,327

Common stock (No par value, 2000 shares authorized, 922 shares and 920 shares outstanding at March 31, 2016 and December 31, 2015, respectively)

  18,686    18,676  

Treasury stock, at cost (35 shares at March 31, 2016 and December 31, 2015, respectively)

  (2,327  (2,327

Retained earnings

   12,046    10,910    11,954    12,068  

Accumulated other comprehensive loss, net

   (2,596  (2,684  (2,596  (2,624
  

 

  

 

  

 

  

 

 

Total shareholders’ equity

   25,770    22,608    25,717    25,793  

BGE preference stock not subject to mandatory redemption

   193    193    193    193  

Noncontrolling interest

   1,326    1,332    1,276    1,308  
  

 

  

 

  

 

  

 

 

Total equity

   27,289    24,133    27,186    27,294  
  

 

  

 

  

 

  

 

 

Total liabilities and shareholders’ equity

  $95,128   $86,814   $111,742   $95,384  
  

 

  

 

  

 

  

 

 

 

(a)

Exelon’s consolidated assets include $8,190$8,310 million and $8,160$8,268 million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,242$3,421 million and $2,723$3,264 million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

 

(In millions, shares

in thousands)

 Issued
Shares
 Common
Stock
 Treasury
Stock
 Retained
Earnings
 Accumulated
Other
Comprehensive
Loss, net
 Noncontrolling
Interest
 Preference
Stock
 Total
Equity
  Issued
Shares
 Common
Stock
 Treasury
Stock
 Retained
Earnings
 Accumulated
Other
Comprehensive
Loss, net
 Noncontrolling
Interest
 Preference
Stock
 Total
Shareholders’

Equity
 

Balance, December 31, 2014

  894,568   $16,709   $(2,327 $10,910   $(2,684 $1,332   $193   $24,133  

Balance, December 31, 2015

  954,668   $18,676   $(2,327 $12,068   $(2,624 $1,308   $193   $27,294  

Net income

              1,959        (10  10    1,959                173        (53  3    123  

Long-term incentive plan activity

  1,394    47                        47    1,783    17                        17  

Employee stock purchase plan issuances

  1,083    24                        24    351    9                        9  

Issuance of common stock

  57,500    1,868                        1,868  

Tax benefit on stock compensation

      (1                      (1      (16                      (16

Changes in equity of noncontrolling interest

                      4        4                        2        2  

Adjustment of contingently redeemable noncontrolling interest due to release of contingency

                      19        19  

Common stock dividends

              (823              (823              (287              (287

Preference stock dividends

                          (10  (10         ��                (3  (3

Other comprehensive income, net of income taxes

                  88            88                    28            28  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Balance, September 30, 2015

  954,545   $18,647   $(2,327 $12,046   $(2,596 $1,326   $193   $27,289  

Balance, March 31, 2016

  956,802   $18,686   $(2,327 $11,954   $(2,596 $1,276   $193   $27,186  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)      2015         2014         2015         2014           2016         2015     

Operating revenues

        

Operating revenues

  $4,562   $4,300   $14,270   $11,944    $4,471   $5,629  

Operating revenues from affiliates

   206    112    571    647     268    211  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating revenues

   4,768    4,412    14,841    12,591     4,739    5,840  
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating expenses

        

Purchased power and fuel

   2,516    1,821    7,789    6,595     2,440    3,426  

Purchased power and fuel from affiliates

   3    59    11    476     2    7  

Operating and maintenance

   1,088    1,114    3,399    3,308     1,296    1,162  

Operating and maintenance from affiliates

   153    152    461    457     171    149  

Depreciation and amortization

   264    253    774    719     289    254  

Taxes other than income

   123    127    369    350     126    122  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating expenses

   4,147    3,526    12,803    11,905     4,324    5,120  
  

 

  

 

  

 

  

 

   

 

  

 

 

Equity in earnings (losses) of unconsolidated affiliates

       1        (20

Gain on sales of assets

   1    338    7    355  

Gain on consolidation and acquisition of businesses

               261  

Loss on sales of assets

       (1
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating income

   622    1,225    2,045    1,282     415    719  
  

 

  

 

  

 

  

 

   

 

  

 

 

Other income and (deductions)

        

Interest expense

   (56  (77  (236  (224

Interest expense to affiliates, net

   (12  (12  (33  (37

Interest expense, net

   (87  (90

Interest expense to affiliates

   (10  (12

Other, net

   (257  4    (193  306     93    94  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total other income and (deductions)

   (325  (85  (462  45     (4  (8
  

 

  

 

  

 

  

 

   

 

  

 

 

Income before income taxes

   297    1,140    1,583    1,327     411    711  

Income taxes

   (36  291    371    290     151    226  

Equity in losses of unconsolidated affiliates

   (1      (4       (3    
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income

   332    849    1,208    1,037     257    485  

Net income (loss) attributable to noncontrolling interests

   (45  78    (10  111  

Net (loss) income attributable to noncontrolling interests

   (53  42  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income attributable to membership interest

  $377   $771   $1,218   $926    $310   $443  
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income, net of income taxes

        

Net income

  $332   $849   $1,208   $1,037    $257   $485  

Other comprehensive income (loss), net of income taxes

        

Unrealized loss on cash flow hedges

   (3  (16  (7  (86   (5  (5

Unrealized gain (loss) on equity investments

       (3      8  

Unrealized loss on foreign currency translation

   (8  (5  (17  (6

Unrealized loss on marketable securities

   (2  (2      (3

Reversal of CENG equity method AOCI

               (116

Unrealized loss on equity investments

   (2    

Unrealized gain (loss) on foreign currency translation

   6    (12
  

 

  

 

  

 

  

 

   

 

  

 

 

Other comprehensive loss

   (13  (26  (24  (203

Other comprehensive income (loss)

   (1  (17
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income

  $319   $823   $1,184   $834    $256   $468  
  

 

  

 

  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)  2015 2014       2016         2015     

Cash flows from operating activities

      

Net income

  $1,208   $1,037    $257   $485  

Adjustments to reconcile net income to net cash flows provided by operating activities:

      

Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization

   1,887    1,853     667    591  

Impairment of long-lived assets

   1    138     119      

Gain on consolidation and acquisitions of businesses

       (268

Gain on sales of assets

   (7  (355

Loss on sales of assets

       1  

Deferred income taxes and amortization of investment tax credits

   21    154     68    89  

Net fair value changes related to derivatives

   (252  509     (106  (165

Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments

   221    (141

Net realized and unrealized gains on nuclear decommissioning trust fund investments

   (55  (47

Other non-cash operating activities

   227    251     51    45  

Changes in assets and liabilities:

      

Accounts receivable

   252    153     173    24  

Receivables from and payables to affiliates, net

   16    72     (17  (10

Inventories

   69    (286   93    228  

Accounts payable, accrued expenses and other current liabilities

   (156  (311

Accounts payable and accrued expenses

   (363  (254

Option premiums received, net

   27    21     17    5  

Counterparty collateral received (posted), net

   376    (634

Collateral received, net

   198    288  

Income taxes

   (70  172     (60  (104

Pension and non-pension postretirement benefit contributions

   (189  (214   (112  (107

Other assets and liabilities

   (425  (367   (148  (232
  

 

  

 

   

 

  

 

 

Net cash flows provided by operating activities

   3,206    1,784     782    837  
  

 

  

 

   

 

  

 

 

Cash flows from investing activities

      

Capital expenditures

   (2,774  (1,961   (1,125  (937

Proceeds from nuclear decommissioning trust fund sales

   4,551    5,464     2,240    1,681  

Investment in nuclear decommissioning trust funds

   (4,737  (5,550   (2,297  (1,747

Acquisition of businesses

   (28  (67   (1  (15

Proceeds from sale of long-lived assets

   144    660         142  

Change in restricted cash

   (84  (116   4    (21

Changes in Exelon intercompany money pool

       44  

Cash and restricted cash acquired from consolidations and acquisitions

       129  

Other investing activities

   (92  (34   (25  (2
  

 

  

 

   

 

  

 

 

Net cash flows used in investing activities

   (3,020  (1,431   (1,204  (899
  

 

  

 

   

 

  

 

 

Cash flows from financing activities

      

Change in short-term borrowings

       7     1,377    (1

Proceeds from short-term borrowings with maturities greater than 90 days

   123      

Issuance of long-term debt

   1,307    1,112     151    806  

Retirement of long-term debt

   (64  (552   (94  (18

Retirement of long-term debt to affiliate

   (550           (550

Changes in Exelon intercompany money pool

   1,205         (1,183  936  

Distribution to member

   (2,368  (440   (55  (1,356

Distributions to noncontrolling interest of consolidated VIE

       (415

Contribution from member

   55    55     44      

Other financing activities

   (6  (67   5    (3
  

 

  

 

   

 

  

 

 

Net cash flows used in financing activities

   (421  (300

Net cash flows provided by (used in) financing activities

   368    (186
  

 

  

 

   

 

  

 

 

Increase (decrease) in cash and cash equivalents

   (235  53  

Decrease in cash and cash equivalents

   (54  (248

Cash and cash equivalents at beginning of period

   780    1,258     431    780  
  

 

  

 

   

 

  

 

 

Cash and cash equivalents at end of period

  $545   $1,311    $377   $532  
  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
ASSETS        

Current assets

        

Cash and cash equivalents

  $545    $780    $377    $431  

Restricted cash and cash equivalents

   242     158     119     123  

Accounts receivable, net

        

Customer

   2,056     2,295     1,963     2,095  

Other

   487     318     434     360  

Mark-to-market derivative assets

   1,116     1,276     1,185     1,365  

Receivables from affiliates

   84     113     154     83  

Unamortized energy contract assets

   135     254     85     86  

Inventories, net

        

Fossil fuel and emission allowances

   357     465     251     384  

Materials and supplies

   863     847     884     880  

Deferred income taxes

   201     327  

Assets held for sale

   4     147  

Other

   960     658     719     535  
  

 

   

 

   

 

   

 

 

Total current assets

   7,050     7,638     6,171     6,342  
  

 

   

 

   

 

   

 

 

Property, plant and equipment, net

   24,982     22,945     26,166     25,843  

Deferred debits and other assets

        

Nuclear decommissioning trust funds

   10,103     10,537     10,526     10,342  

Investments

   197     104     250     210  

Goodwill

   47     47     47     47  

Mark-to-market derivative assets

   764     771     799     733  

Prepaid pension asset

   1,703     1,704     1,725     1,689  

Pledged assets for Zion Station decommissioning

   237     319     183     206  

Unamortized energy contract assets

   513     549     473     484  

Deferred income taxes

   2     3     12     6  

Other

   881     731     650     627  
  

 

   

 

   

 

   

 

 

Total deferred debits and other assets

   14,447     14,765     14,665     14,344  
  

 

   

 

   

 

   

 

 

Total assets(a)

  $46,479    $45,348    $47,002    $46,529  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
 December 31,
2014
   March 31,
2016
 December 31,
2015
 
  (Unaudited)     (Unaudited)   
LIABILITIES AND EQUITY      

Current liabilities

      

Short-term borrowings

  $21   $36    $1,529   $29  

Long-term debt due within one year

   97    58     177    90  

Long-term debt to affiliates due within one year

       556  

Accounts payable

   1,676    1,759     1,290    1,583  

Accrued expenses

   835    886     673    935  

Payables to affiliates

   106    107     140    104  

Borrowings from Exelon intercompany money pool

   1,205         63    1,252  

Mark-to-market derivative liabilities

   182    214     177    182  

Unamortized energy contract liabilities

   118    238     85    100  

Renewable energy credit obligation

   308    302  

Other

   546    605     333    356  
  

 

  

 

   

 

  

 

 

Total current liabilities

   4,786    4,459     4,775    4,933  
  

 

  

 

   

 

  

 

 

Long-term debt

   7,964    6,709     7,945    7,936  

Long-term debt to affiliate

   935    943     930    933  

Deferred credits and other liabilities

      

Deferred income taxes and unamortized investment tax credits

   6,030    6,034     5,872    5,845  

Asset retirement obligations

   8,254    7,146     8,588    8,431  

Non-pension postretirement benefit obligations

   926    915     937    924  

Spent nuclear fuel obligation

   1,021    1,021     1,022    1,021  

Payables to affiliates

   2,538    2,880     2,600    2,577  

Mark-to-market derivative liabilities

   139    105     166    150  

Unamortized energy contract liabilities

   136    211     106    117  

Payable for Zion Station decommissioning

   99    155     71    90  

Other

   727    719     637    602  
  

 

  

 

   

 

  

 

 

Total deferred credits and other liabilities

   19,870    19,186     19,999    19,757  
  

 

  

 

   

 

  

 

 

Total liabilities(a)

   33,555    31,297     33,649    33,559  
  

 

  

 

   

 

  

 

 

Commitments and contingencies

      

Contingently redeemable noncontrolling interests

   19    28  

Equity

      

Member’s equity

      

Membership interest

   9,006    8,951     9,167    8,997  

Undistributed earnings

   2,653    3,803     2,956    2,701  

Accumulated other comprehensive loss, net

   (60  (36   (64  (63
  

 

  

 

   

 

  

 

 

Total member’s equity

   11,599    12,718     12,059    11,635  

Noncontrolling interest

   1,325    1,333     1,275    1,307  
  

 

  

 

   

 

  

 

 

Total equity

   12,924    14,051     13,334    12,942  
  

 

  

 

   

 

  

 

 

Total liabilities and equity

  $46,479   $45,348    $47,002   $46,529  
  

 

  

 

   

 

  

 

 

 

(a)

Generation’s consolidated assets include $8,130$8,190 million and $8,119$8,235 million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,070$3,094 million and $2,507$3,135 million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 — 3—Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

 

   Member’s Equity       
(In millions)  Membership
Interest
   Undistributed
Earnings
  Accumulated
Other
Comprehensive
Loss, net
  Noncontrolling
Interest
  Total
Equity
 

Balance, December 31, 2014

  $8,951    $3,803   $(36 $1,333   $14,051  

Net income

        1,218        (10  1,208  

Changes in equity of noncontrolling interest

                2    2  

Allocation of tax benefit from member

   55                 55  

Distribution to member

        (2,368          (2,368

Other comprehensive loss, net of income taxes

            (24      (24
  

 

 

   

 

 

  

 

 

  

 

 

  

 

 

 

Balance, September 30, 2015

  $9,006    $2,653   $(60 $1,325   $12,924  
  

 

 

   

 

 

  

 

 

  

 

 

  

 

 

 
   Member’s Equity       
(In millions)  Membership
Interest
   Undistributed
Earnings
  Accumulated
Other
Comprehensive
Loss, net
  Noncontrolling
Interest
  Total Equity 

Balance, December 31, 2015

  $8,997    $2,701   $(63 $1,307   $12,942  

Net income (loss)

        310        (53  257  

Acquisition of non-controlling interest

                2    2  

Adjustment of contingently redeemable noncontrolling interest due to release of contingency

                19    19  

Contribution from member

   170                 170  

Distribution to member

        (55          (55

Other comprehensive loss, net of income taxes

            (1      (1
  

 

 

   

 

 

  

 

 

  

 

 

  

 

 

 

Balance, March 31, 2016

  $9,167    $2,956   $(64 $1,275   $13,334  
  

 

 

   

 

 

  

 

 

  

 

 

  

 

 

 

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)      2015         2014         2015     2014            2016           2015      

Operating revenues

        

Operating revenues

  $1,375   $1,221   $3,706   $3,482  

Electric operating revenues

  $1,244   $1,184  

Operating revenues from affiliates

   1    1    3    2     5    1  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating revenues

   1,376    1,222    3,709    3,484     1,249    1,185  
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating expenses

        

Purchased power

   388    325    974    741     343    318  

Purchased power from affiliate

   2    1    17    174     5    9  

Operating and maintenance

   353    320    1,023    923     305    333  

Operating and maintenance from affiliate

   51    39    143    117     63    45  

Depreciation and amortization

   176    174    528    521     189    175  

Taxes other than income

   79    76    225    225     75    75  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating expenses

   1,049    935    2,910    2,701     980    955  
  

 

  

 

 

Gain on sale of assets

   5      
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating income

   327    287    799    783     274    230  
  

 

  

 

  

 

  

 

   

 

  

 

 

Other income and (deductions)

        

Interest expense, net

   (80  (78  (238  (231   (83  (81

Interest expense to affiliates

   (3  (3  (10  (10   (3  (3

Other, net

   4    4    14    14     4    3  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total other income and (deductions)

   (79  (77  (234  (227   (82  (81
  

 

  

 

  

 

  

 

   

 

  

 

 

Income before income taxes

   248    210    565    556     192    149  

Income taxes

   99    84    226    221     77    59  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income

   149    126    339    335    $115   $90  
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income

  $149   $126   $339   $335    $115   $90  
  

 

  

 

  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)  2015 2014       2016         2015     

Cash flows from operating activities

      

Net income

  $339   $335    $115   $90  

Adjustments to reconcile net income to net cash flows provided by operating activities:

      

Depreciation, amortization and accretion

   528    521     189    175  

Deferred income taxes and amortization of investment tax credits

   107    154     70    35  

Other non-cash operating activities

   312    116     32    126  

Changes in assets and liabilities:

      

Accounts receivable

   (114  (109   69    (38

Receivables from and payables to affiliates, net

   (23  (55       (2

Inventories

   (23  (12   7    (10

Accounts payable, accrued expenses and other current liabilities

   (20  59  

Accounts payable and accrued expenses

   (207  (121

Collateral received (posted), net

   7    (5

Income taxes

   389    15     20    131  

Pension and non-pension postretirement benefit contributions

   (142  (237   (32  (121

Other assets and liabilities

   (7  62     14    (9
  

 

  

 

   

 

  

 

 

Net cash flows provided by operating activities

   1,346    849     284    251  
  

 

  

 

   

 

  

 

 

Cash flows from investing activities

      

Capital expenditures

   (1,670  (1,173   (639  (530

Proceeds from sales of investments

       7  

Change in restricted cash

   2    (2

Other investing activities

   22    20     13    7  
  

 

  

 

   

 

  

 

 

Net cash flows used in investing activities

   (1,646  (1,148   (626  (523
  

 

  

 

   

 

  

 

 

Cash flows from financing activities

      

Changes in short-term borrowings

   300    344     349    (21

Issuance of long-term debt

   400    650         400  

Retirement of long-term debt

   (260  (617

Contributions from parent

   75    168     39    14  

Dividends paid on common stock

   (226  (230   (91  (75

Other financing activities

   (4  (8   (1  (4
  

 

  

 

   

 

  

 

 

Net cash flows provided by financing activities

   285    307     296    314  
  

 

  

 

   

 

  

 

 

Increase (decrease) in cash and cash equivalents

   (15  8  

(Decrease) Increase in cash and cash equivalents

   (46  42  

Cash and cash equivalents at beginning of period

   66    36     67    66  
  

 

  

 

   

 

  

 

 

Cash and cash equivalents at end of period

  $51   $44    $21   $108  
  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
ASSETS        

Current assets

        

Cash and cash equivalents

  $51    $66    $21    $67  

Restricted cash

   2     4     2     2  

Accounts receivable, net

        

Customer

   557     477     479     533  

Other

   334     648     221     272  

Receivables from affiliates

   14     14     202     199  

Inventories, net

   148     125     157     164  

Regulatory assets

   232     349     239     218  

Other

   84     40     51     63  
  

 

   

 

   

 

   

 

 

Total current assets

   1,422     1,723     1,372     1,518  
  

 

   

 

   

 

   

 

 

Property, plant and equipment, net

   17,001     15,793     17,971     17,502  

Deferred debits and other assets

        

Regulatory assets

   913     852     925     895  

Investments

   6     6  

Goodwill

   2,625     2,625     2,625     2,625  

Receivables from affiliates

   2,336     2,571     2,182     2,172  

Prepaid pension asset

   1,537     1,551     1,476     1,490  

Other

   295     277     330     324  
  

 

   

 

   

 

   

 

 

Total deferred debits and other assets

   7,706     7,876     7,544     7,512  
  

 

   

 

   

 

   

 

 

Total assets

  $26,129    $25,392    $26,887    $26,532  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
LIABILITIES AND SHAREHOLDERS’ EQUITY        

Current liabilities

        

Short-term borrowings

  $604    $304    $643    $294  

Long-term debt due within one year

   665     260     665     665  

Accounts payable

   693     598     645     660  

Accrued expenses

   337     331     539     706  

Payables to affiliates

   60     84     64     62  

Customer deposits

   130     128     130     131  

Regulatory liabilities

   144     125     150     155  

Deferred income taxes

        63  

Mark-to-market derivative liability

   22     20     26     23  

Other

   68     73     76     70  
  

 

   

 

   

 

   

 

 

Total current liabilities

   2,723     1,986     2,938     2,766  
  

 

   

 

   

 

   

 

 

Long-term debt

   5,435     5,698     5,845     5,844  

Long-term debt to financing trust

   206     206     205     205  

Deferred credits and other liabilities

        

Deferred income taxes and unamortized investment tax credits

   4,677     4,498     4,985     4,914  

Asset retirement obligations

   110     103     113     111  

Non-pension postretirement benefits obligations

   262     263     254     259  

Regulatory liabilities

   3,441     3,655     3,489     3,459  

Mark-to-market derivative liability

   221     187     239     224  

Other

   954     889     512     507  
  

 

   

 

   

 

   

 

 

Total deferred credits and other liabilities

   9,665     9,595     9,592     9,474  
  

 

   

 

   

 

   

 

 

Total liabilities

   18,029     17,485     18,580     18,289  
  

 

   

 

   

 

   

 

 

Commitments and contingencies

        

Shareholders’ equity

        

Common stock

   1,588     1,588     1,588     1,588  

Other paid-in capital

   5,548     5,468     5,717     5,677  

Retained earnings

   964     851     1,002     978  
  

 

   

 

   

 

   

 

 

Total shareholders’ equity

   8,100     7,907     8,307     8,243  
  

 

   

 

   

 

   

 

 

Total liabilities and shareholders’ equity

  $26,129    $25,392    $26,887    $26,532  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

 

(In millions)  Common
Stock
   Other Paid-
In  Capital
   Retained Deficit
Unappropriated
 Retained
Earnings
Appropriated
 Total
Shareholders’
Equity
   Common
Stock
   Other
Paid-In
Capital
   Retained Deficit
Unappropriated
 Retained
Earnings
Appropriated
 Total
Shareholders’
Equity
 

Balance, December 31, 2014

  $1,588    $5,468    $(1,639 $2,490   $7,907  

Balance, December 31, 2015

  $1,588    $5,677    $(1,639 $2,617   $8,243  

Net income

             339        339               115        115  

Appropriation of retained earnings for future dividends

             (339  339                   (115  115      

Common stock dividends

                 (226  (226                 (91  (91

Contribution from parent

        75             75          39             39  

Parent tax matter indemnification

        5             5          1             1  
  

 

   

 

   

 

  

 

  

 

   

 

   

 

   

 

  

 

  

 

 

Balance, September 30, 2015

  $1,588    $5,548    $(1,639 $2,603   $8,100  

Balance, March 31, 2016

  $1,588    $5,717    $(1,639 $2,641   $8,307  
  

 

   

 

   

 

  

 

  

 

   

 

   

 

   

 

  

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)      2015         2014         2015         2014           2016         2015     

Operating revenues

        

Operating revenues

  $739   $693   $2,385   $2,342  

Electric operating revenues

  $643   $677  

Natural gas operating revenues

   197    308  

Operating revenues from affiliates

   1        1    1     1      
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating revenues

   740    693    2,386    2,343     841    985  
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating expenses

        

Purchased power and fuel

   217    228    782    798  

Purchased power

   166    216  

Purchased fuel

   77    160  

Purchased power from affiliate

   61    27    171    162     78    62  

Operating and maintenance

   166    181    529    597     177    197  

Operating and maintenance from affiliates

   30    23    80    71     38    25  

Depreciation and amortization

   68    59    198    176     67    62  

Taxes other than income

   44    42    125    122     42    41  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating expenses

   586    560    1,885    1,926     645    763  
  

 

  

 

  

 

  

 

   

 

  

 

 

Gain on sale of assets

           1      

Gain on sales of assets

       1  
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating income

   154    133    502    417     196    223  
  

 

  

 

  

 

  

 

   

 

  

 

 

Other income and (deductions)

        

Interest expense, net

   (25  (26  (75  (76   (28  (25

Interest expense to affiliates

   (3  (3  (9  (9   (3  (3

Other, net

   1    2    3    5     2    2  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total other income and (deductions)

   (27  (27  (81  (80   (29  (26
  

 

  

 

  

 

  

 

   

 

  

 

 

Income before income taxes

   127    106    421    337     167    197  

Income taxes

   37    25    122    82     43    58  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income attributable to common shareholder

   90    81    299    255    $124   $139  
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income

  $90   $81   $299   $255    $124   $139  
  

 

  

 

  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)      2015         2014           2016         2015     

Cash flows from operating activities

      

Net income

  $299   $255    $124   $139  

Adjustments to reconcile net income to net cash flows provided by operating activities:

      

Depreciation, amortization and accretion

   198    176     67    62  

Deferred income taxes and amortization of investment tax credits

   11    7     23    5  

Other non-cash operating activities

   69    70     24    44  

Changes in assets and liabilities:

      

Accounts receivable

   (15  63     (51  (115

Receivables from and payables to affiliates, net

       (20   4    5  

Inventories

   8    5     24    34  

Accounts payable, accrued expenses and other current liabilities

   (17  19  

Accounts payable and accrued expenses

   18    (1

Income taxes

   69    16     29    67  

Pension and non-pension postretirement benefit contributions

   (37  (12   (29  (12

Other assets and liabilities

   (18  (75   (95  (70
  

 

  

 

   

 

  

 

 

Net cash flows provided by operating activities

   567    504     138    158  
  

 

  

 

   

 

  

 

 

Cash flows from investing activities

      

Capital expenditures

   (435  (461   (195  (148

Change in restricted cash

   (1    

Changes in Exelon intercompany money pool

   (160    

Other investing activities

   11    9     4    4  
  

 

  

 

   

 

  

 

 

Net cash flows used in investing activities

   (425  (452   (351  (144
  

 

  

 

   

 

  

 

 

Cash flows from financing activities

      

Issuance of long-term debt

       300  

Contributions from parent

   16    24  

Change in Exelon intercompany money pool

   55      

Changes in Exelon intercompany money pool

       65  

Dividends paid on common stock

   (209  (240   (69  (70

Other financing activities

   (2  (7       (1
  

 

  

 

   

 

  

 

 

Net cash flows provided by (used in) financing activities

   (140  77  

Net cash flows used in financing activities

   (69  (6
  

 

  

 

   

 

  

 

 

Increase in cash and cash equivalents

   2    129  

Increase (decrease) in cash and cash equivalents

   (282  8  

Cash and cash equivalents at beginning of period

   30    217     295    30  
  

 

  

 

   

 

  

 

 

Cash and cash equivalents at end of period

  $32   $346    $13   $38  
  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
ASSETS        

Current assets

        

Cash and cash equivalents

  $32    $30    $13    $295  

Restricted cash and cash equivalents

   3     2     3     3  

Accounts receivable, net

        

Customer

   283     320     288     258  

Other

   122     141     124     146  

Receivables from affiliates

   4     3     5     2  

Receivable from Exelon intercompany pool

   160       

Inventories, net

        

Fossil fuel

   43     57     18     43  

Materials and supplies

   28     22     27     26  

Deferred income taxes

   69     69  

Prepaid utility taxes

   42     10     110     11  

Regulatory assets

   32     29     42     34  

Other

   25     31     26     24  
  

 

   

 

   

 

   

 

 

Total current assets

   683     714     816     842  
  

 

   

 

   

 

   

 

 

Property, plant and equipment, net

   7,027     6,801     7,209     7,141  

Deferred debits and other assets

        

Regulatory assets

   1,557     1,529     1,605     1,583  

Investments

   28     31     27     28  

Receivable from affiliates

   388     490     417     405  

Prepaid pension asset

   353     344     368     347  

Other

   36     34     20     21  
  

 

   

 

   

 

   

 

 

Total deferred debits and other assets

   2,362     2,428     2,437     2,384  
  

 

   

 

   

 

   

 

 

Total assets

  $10,072    $9,943    $10,462    $10,367  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
LIABILITIES AND SHAREHOLDERS’ EQUITY    
LIABILITIES AND SHAREHOLDER’S EQUITY    

Current liabilities

        

Long-term debt due within one year

  $300    $300  

Accounts payable

  $298    $337     261     281  

Accrued expenses

   123     91     84     109  

Payables to affiliates

   53     52     62     55  

Borrowings from Exelon intercompany money pool

   55       

Customer deposits

   56     52     59     58  

Regulatory liabilities

   104     90     134     112  

Other

   30     31     33     29  
  

 

   

 

   

 

   

 

 

Total current liabilities

   719     653     933     944  
  

 

   

 

   

 

   

 

 

Long-term debt

   2,246     2,246     2,281     2,280  

Long-term debt to financing trusts

   184     184     184     184  

Deferred credits and other liabilities

        

Deferred income taxes and unamortized investment tax credits

   2,752     2,671     2,849     2,792  

Asset retirement obligations

   26     29     27     27  

Non-pension postretirement benefits obligations

   288     287     288     287  

Regulatory liabilities

   536     657     521     527  

Other

   94     95     88     90  
  

 

   

 

   

 

   

 

 

Total deferred credits and other liabilities

   3,696     3,739     3,773     3,723  
  

 

   

 

   

 

   

 

 

Total liabilities

   6,845     6,822     7,171     7,131  
  

 

   

 

   

 

   

 

 

Commitments and contingencies

        

Shareholder’s equity

        

Common stock

   2,455     2,439     2,455     2,455  

Retained earnings

   771     681     835     780  

Accumulated other comprehensive income, net

   1     1     1     1  
  

 

   

 

   

 

   

 

 

Total shareholder’s equity

   3,227     3,121     3,291     3,236  
  

 

   

 

   

 

   

 

 

Total liabilities and shareholder’s equity

  $10,072    $9,943    $10,462    $10,367  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

 

(In millions)  Common
Stock
   Retained
Earnings
 Accumulated
Other
Comprehensive
Income, net
   Total
Equity
   Common
Stock
   Retained
Earnings
 Accumulated
Other
Comprehensive
Income, net
   Total
Shareholder’s
Equity
 

Balance, December 31, 2014

  $2,439    $681   $1    $3,121  

Balance, December 31, 2015

  $2,455    $780   $1    $3,236  

Net income

        299         299          124         124  

Allocation of tax benefit from parent

   16              16  

Common stock dividends

        (209       (209        (69       (69
  

 

   

 

  

 

   

 

   

 

   

 

  

 

   

 

 

Balance, September 30, 2015

  $2,455    $771   $1    $3,227  

Balance, March 31, 2016

  $2,455    $835   $1    $3,291  
  

 

   

 

  

 

   

 

   

 

   

 

  

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)      2015         2014         2015         2014           2016         2015     

Operating revenue

     

Operating revenue

  $722   $694   $2,378   $2,383  

Operating revenue from affiliates

   3    3    10    21  

Operating revenues

   

Electric operating revenues

  $678   $714  

Natural gas operating revenues

   246    315  

Operating revenues from affiliates

   5    7  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating revenues

   725    697    2,388    2,404     929    1,036  
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating expenses

        

Purchased power and fuel

   170    216    664    808  

Purchased power

   127    208  

Purchased fuel

   75    142  

Purchased power from affiliate

   141    81    373    286     171    137  

Operating and maintenance

   138    142    412    468     168    156  

Operating and maintenance from affiliates

   31    23    87    73     34    26  

Depreciation and amortization

   79    78    271    275     109    106  

Taxes other than income

   57    55    169    168     58    57  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total operating expenses

   616    595    1,976    2,078     742    832  
  

 

  

 

  

 

  

 

 

Gain on sale of assets

   1        1      
  

 

  

 

  

 

  

 

   

 

  

 

 

Operating income

   110    102    413    326     187    204  
  

 

  

 

  

 

  

 

   

 

  

 

 

Other income and (deductions)

        

Interest expense, net

   (21  (22  (62  (69   (20  (21

Interest expense to affiliates

   (4  (4  (11  (12   (4  (4

Other, net

   4    4    13    14     4    4  
  

 

  

 

  

 

  

 

   

 

  

 

 

Total other income and (deductions)

   (21  (22  (60  (67   (20  (21
  

 

  

 

  

 

  

 

   

 

  

 

 

Income before income taxes

   89    80    353    259     167    183  

Income taxes

   35    31    141    103     66    74  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income

   54    49    212    156     101    109  

Preference stock dividends

   3    3    10    10     3    3  
  

 

  

 

  

 

  

 

   

 

  

 

 

Net income attributable to common shareholder

   51    46    202    146    $98   $106  
  

 

  

 

  

 

  

 

   

 

  

 

 

Comprehensive income

  $54   $49   $212   $156    $101   $109  
  

 

  

 

  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
(In millions)      2015         2014           2016         2015     

Cash flows from operating activities

      

Net income

  $212   $156    $101   $109  

Adjustments to reconcile net income to net cash flows provided by operating activities:

      

Depreciation, amortization and accretion

   271    275     109    106  

Deferred income taxes and amortization of investment tax credits

   79    57     26    33  

Other non-cash operating activities

   111    129     44    64  

Changes in assets and liabilities:

      

Accounts receivable

   62    101     (44  (141

Receivables from and payables to affiliates, net

   (8  (11   7    (8

Inventories

   10    (21   17    38  

Accounts payable, accrued expenses and other current liabilities

   49    (50

Counterparty collateral (posted) received, net

   (27  16  

Accounts payable and accrued expenses

   3    (14

Collateral received (posted), net

       (27

Income taxes

   (6  53     78    26  

Pension and non-pension postretirement benefit contributions

   (14  (13   (38  (4

Other assets and liabilities

   (43  (67   (30  99  
  

 

  

 

   

 

  

 

 

Net cash flows provided by operating activities

   696    625     273    281  
  

 

  

 

   

 

  

 

 

Cash flows from investing activities

      

Capital expenditures

   (506  (458   (176  (136

Change in restricted cash

   2    (37   (20  2  

Other investing activities

   13    15     5    2  
  

 

  

 

   

 

  

 

 

Net cash flows used in investing activities

   (491  (480   (191  (132
  

 

  

 

   

 

  

 

 

Cash flows from financing activities

      

Changes in short-term borrowings

   (70  (115   (60  (120

Retirement of long-term debt

   (37  (35

Contributions from parent

   6      

Dividends paid on preference stock

   (10  (10   (3  (3

Dividends paid on common stock

   (116       (45  (36

Contributions from parent

   21      

Other financing activities

   (15  11     1    (13
  

 

  

 

   

 

  

 

 

Net cash flows used in financing activities

   (242  (149   (86  (172
  

 

  

 

   

 

  

 

 

Decrease in cash and cash equivalents

   (37  (4   (4  (23

Cash and cash equivalents at beginning of period

   64    31     9    64  
  

 

  

 

   

 

  

 

 

Cash and cash equivalents at end of period

  $27   $27    $5   $41  
  

 

  

 

   

 

  

 

 

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
ASSETS        

Current assets

        

Cash and cash equivalents

  $27    $64    $5    $9  

Restricted cash and cash equivalents

   48     50     44     24  

Accounts receivable, net

        

Customer

   318     390     328     300  

Other

   77     82     77     112  

Receivables from affiliates

   1       

Inventories, net

        

Gas held in storage

   42     57     13     36  

Materials and supplies

   35     30     39     33  

Deferred income taxes

   8     6  

Prepaid utility taxes

   4     59     31     61  

Regulatory assets

   257     214     266     267  

Other

   5     5     16     3  
  

 

   

 

   

 

   

 

 

Total current assets

   822     957     819     845  
  

 

   

 

   

 

   

 

 

Property, plant and equipment, net

   6,459     6,204     6,684     6,597  

Deferred debits and other assets

        

Regulatory assets

   485     510     499     514  

Investments

   12     12     12     12  

Prepaid pension asset

   331     370     337     319  

Other

   25     25     10     8  
  

 

   

 

   

 

   

 

 

Total deferred debits and other assets

   853     917     858     853  
  

 

   

 

   

 

   

 

 

Total assets(a)

  $8,134    $8,078    $8,361    $8,295  
  

 

   

 

   

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

 

(In millions)  September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 
  (Unaudited)       (Unaudited)     
LIABILITIES AND SHAREHOLDERS’ EQUITY        

Current liabilities

        

Short-term borrowings

  $50    $120    $150    $210  

Long-term debt due within one year

   77     75     378     378  

Accounts payable

   201     215     206     209  

Accrued expenses

   159     131     151     110  

Deferred income taxes

   63     52  

Payables to affiliates

   47     66     59     52  

Customer deposits

   99     92     105     102  

Regulatory liabilities

   69     44     61     38  

Other

   32     51     28     35  
  

 

   

 

   

 

   

 

 

Total current liabilities

   797     846     1,138     1,134  
  

 

   

 

   

 

   

 

 

Long-term debt

   1,828     1,867     1,481     1,480  

Long-term debt to financing trust

   258     258     252     252  

Deferred credits and other liabilities

        

Deferred income taxes and unamortized investment tax credits

   1,937     1,865     2,104     2,081  

Asset retirement obligations

   15     17     15     17  

Non-pension postretirement benefits obligations

   209     212     205     209  

Regulatory liabilities

   186     200     151     184  

Other

   59     60     71     61  
  

 

   

 

   

 

   

 

 

Total deferred credits and other liabilities

   2,406     2,354     2,546     2,552  
  

 

   

 

   

 

   

 

 

Total liabilities(a)

   5,289     5,325     5,417     5,418  
  

 

   

 

   

 

   

 

 

Commitments and contingencies

        

Shareholders’ equity

        

Common stock

   1,366     1,360     1,381     1,367  

Retained earnings

   1,289     1,203     1,373     1,320  
  

 

   

 

   

 

   

 

 

Total shareholders’ equity

   2,655     2,563     2,754     2,687  
  

 

   

 

 

Preference stock not subject to mandatory redemption

   190     190     190     190  
  

 

   

 

   

 

   

 

 

Total equity

   2,845     2,753     2,944     2,877  
  

 

   

 

   

 

   

 

 

Total liabilities and shareholders’ equity

  $8,134    $8,078    $8,361    $8,295  
  

 

   

 

   

 

   

 

 

 

(a)

BGE’s consolidated assets include $49$47 million and $24$26 million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $162$41 million and $197$41 million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

 

(In millions)  Common
Stock
   Retained
Earnings
 Total
Shareholders’
Equity
 Preference Stock
Not Subject to
Mandatory
Redemption
   Total Equity   Common
Stock
 Retained
Earnings
 Total
Shareholders’
Equity
 Preference Stock
Not Subject To
Mandatory
Redemption
   Total Equity 

Balance, December 31, 2014

  $1,360    $1,203   $2,563   $190    $2,753  

Balance, December 31, 2015

  $1,367   $1,320   $2,687   $190    $2,877  

Net income

        212    212         212         101    101         101  

Allocation of tax benefit from parent

   6         6         6  

Preference stock dividends

        (10  (10       (10       (3  (3       (3

Common stock dividends

        (116  (116       (116       (45  (45       (45

Distribution to parent

   (7      (7       (7

Contribution from parent

   21        21         21  
  

 

   

 

  

 

  

 

   

 

   

 

  

 

  

 

  

 

   

 

 

Balance, September 30, 2015

  $1,366    $1,289   $2,655   $190    $2,845  

Balance, March 31, 2016

  $1,381   $1,373   $2,754   $190    $2,944  
  

 

   

 

  

 

  

 

   

 

   

 

  

 

  

 

  

 

   

 

 

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

   Successor     Predecessor 
   March 24 to
March 31,
     January 1 to
March 23,
  Three Months
Ended March 31,
 
(In millions)  2016     2016  2015 

Operating revenues

      

Electric operating revenues

  $90     $1,096   $1,268  

Natural gas operating revenues

   3      57    86  

Operating revenues from affiliates

   12            
  

 

 

    

 

 

  

 

 

 

Total operating revenues

   105      1,153    1,354  
  

 

 

    

 

 

  

 

 

 

Operating expenses

      

Purchased power

   26      471    588  

Purchased fuel

   1      26    51  

Purchased power and fuel from affiliates

   11            

Operating and maintenance

   447      294    300  

Operating and maintenance from affiliates

   2            

Depreciation and amortization

   14      152    155  

Taxes other than income

   15      105    118  
  

 

 

    

 

 

  

 

 

 

Total operating expenses

   516      1,048    1,212  
  

 

 

    

 

 

  

 

 

 

Operating (loss) income

   (411    105    142  
  

 

 

    

 

 

  

 

 

 

Other income and (deductions)

      

Interest expense, net

   (6    (65  (68

Other, net

   2      (4  9  
  

 

 

    

 

 

  

 

 

 

Total other income and (deductions)

   (4    (69  (59
  

 

 

    

 

 

  

 

 

 

(Loss) Income before income taxes

   (415    36    83  

Income taxes

   (106    17    30  
  

 

 

    

 

 

  

 

 

 

Net (loss) income attributable to membership interest/common shareholders

  $(309   $19   $53  
  

 

 

    

 

 

  

 

 

 

Comprehensive (loss) income, net of income taxes

      

Net (loss) income

  $(309   $19   $53  

Other comprehensive income, net of income taxes

      

Pension and non-pension postretirement benefit plans:

      

Actuarial loss reclassified to periodic cost

         1    1  
  

 

 

    

 

 

  

 

 

 

Other comprehensive income

         1    1  
  

 

 

    

 

 

  

 

 

 

Comprehensive (loss) income

  $(309   $20   $54  
  

 

 

    

 

 

  

 

 

 

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

   Successor     Predecessor 
   March 24 to
March 31,
     January 1 to
March 23,
  Three Months Ended
March 31,
 
(In millions)  2016     2016  2015 

Cash flows from operating activities

      

Net (loss) income

  $(309   $19   $53  

Adjustments to reconcile net (loss) income to net cash from operating activities:

      

Depreciation, amortization and accretion

   14      152    155  

Deferred income taxes and amortization of investment tax credits

   (112    19    49  

Net fair value changes related to derivatives

         18      

Other non-cash operating activities

   410      46    57  

Changes in assets and liabilities:

      

Accounts receivable

   16      (28  (214

Receivables from and payables to affiliates, net

   46            

Inventories

         (4  (3

Accounts payable and accrued expenses

   (4    42    43  

Collateral received, net

         1      

Income taxes

   7      12    (3

Pension and non-pension postretirement benefit contributions

         (4  (5

Other assets and liabilities

   (25    (9  25  
  

 

 

    

 

 

  

 

 

 

Net cash flows provided by operating activities

   43      264    157  
  

 

 

    

 

 

  

 

 

 

Cash flows from investing activities

      

Capital expenditures

   (29    (273  (246

Changes in restricted cash

   (1    3    9  

Purchases of investments

   (2    (68    

Other investing activities

   2      (5  2  
  

 

 

    

 

 

  

 

 

 

Net cash flows used in investing activities

   (30    (343  (235
  

 

 

    

 

 

  

 

 

 

Cash flows from financing activities

      

Changes in short-term borrowings

   (20    (121  74  

Proceeds from short-term borrowings with maturities greater than 90 days

      500      

Issuance of long-term debt

             208  

Retirement of long-term debt

         (11  (22

Issuance of preferred stock

             18  

Dividends paid on common stock

             (68

Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation

         2    8  

Distribution to member

   (108          

Change in Exelon intercompany money pool

   (53          

Other financing activities

         2    (13
  

 

 

    

 

 

  

 

 

 

Net cash flows provided by financing activities

   (181    372    205  
  

 

 

    

 

 

  

 

 

 

(Decrease) Increase in cash and cash equivalents

   (168    293    127  

Cash and cash equivalents at beginning of period

   319      26    15  
  

 

 

    

 

 

  

 

 

 

Cash and cash equivalents at end of period

  $151     $319   $142  
  

 

 

    

 

 

  

 

 

 

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

   Successor     Predecessor 
(In millions)  March 31, 2016     December 31, 2015 
   (Unaudited)       
ASSETS     

Current assets

     

Cash and cash equivalents

  $151     $26  

Restricted cash and cash equivalents

   12      14  

Accounts receivable, net

     

Customer

   536      581  

Other

   284      316  

Mark-to-market derivative asset

         18  

Receivable from affiliates

   16        

Inventories, net

     

Gas held in storage

   4      9  

Materials and supplies

   122      122  

Regulatory assets

   801      305  

Other

   75      81  
  

 

 

    

 

 

 

Total current assets

   2,001      1,472  
  

 

 

    

 

 

 

Property, plant and equipment, net

   10,980      10,864  

Deferred debits and other assets

     

Regulatory assets

   3,202      2,277  

Investments

   131      80  

Goodwill

   4,016      1,406  

Long-term note receivable

   4      4  

Prepaid pension asset

   517        

Unamortized energy contract assets

   1        

Deferred income taxes

   23      14  

Other

   57      67  
  

 

 

    

 

 

 

Total deferred debits and other assets

   7,951      3,848  
  

 

 

    

 

 

 

Total assets(a)

  $20,932     $16,184  
  

 

 

    

 

 

 

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

   Successor     Predecessor 
(In millions)  March 31,
2016
     December 31,
2015
 
   (Unaudited)       
LIABILITIES AND EQUITY     

Current liabilities

     

Short-term borrowings

  $1,317     $958  

Long-term debt due within one year

   476      456  

Accounts payable

   348      404  

Accrued expenses

   327      263  

Payables to affiliates

   66        

Unamortized energy contract liabilities

   497        

Customer deposits

   121      107  

Merger related obligation

   235        

Regulatory liabilities

   106      66  

Other

   51      70  
  

 

 

    

 

 

 

Total current liabilities

   3,544      2,324  
  

 

 

    

 

 

 

Long-term debt

   5,656      4,823  

Deferred credits and other liabilities

     

Regulatory liabilities

   186      147  

Deferred income taxes and unamortized investment tax credits

   3,399      3,406  

Asset retirement obligations

   5      8  

Pension obligations

         466  

Non-pension postretirement benefit obligations

   143      215  

Unamortized energy contract liabilities

   1,038        

Other

   289      199  
  

 

 

    

 

 

 

Total deferred credits and other liabilities

   5,060      4,441  
  

 

 

    

 

 

 

Total liabilities(a)

   14,260      11,588  
  

 

 

    

 

 

 

Commitments and contingencies

     

Preferred stock(b)

         183  

Member’s equity/Shareholders’ equity

     

Membership interest/Common stock(c)

   6,981      3,832  

Undistributed (losses)/Retained earnings

   (309    617  

Accumulated other comprehensive loss, net

         (36
  

 

 

    

 

 

 

Total member’s equity/shareholders’ equity

   6,672      4,413  
  

 

 

    

 

 

 

Total liabilities and member’s equity/shareholders’ equity

  $20,932     $16,184  
  

 

 

    

 

 

 

(a)

PHI’s consolidated total assets include $68 million and $30 million at March 31, 2016 and December 31, 2015, respectively, of PHI’s consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $200 million and $172 million at March 31, 2016 and December 31, 2015, respectively, of PHI’s consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 — Variable Interest Entities.

(b)

At December 31, 2015, PHI had 18,000 shares of Series A preferred stock outstanding, par value $0.01 per share.

(c)

At December 31, 2015, PHI’s (predecessor) shareholders’ equity included $3,829 million of other paid-in capital and $3 million of common stock. At December 31, 2015, PHI had 400,000,000 shares of common stock authorized and 254,289,261 shares of common stock outstanding, par value $0.01 per share.

See the Combined Notes to Consolidated Financial Statements

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

(In millions, except shares)  Common
Stock/
Membership
Interest(a)
  Retained
Earnings/
Undistributed
Losses
  Accumulated
Other
Comprehensive

Loss, net
  Total
Shareholders’/

Member’s
Equity
 

Predecessor

     

Balance at December 31, 2015

  $3,832   $617   $(36 $4,413  

Net income

       19        19  

Original issue shares, net

   3            3  

Net activity related to stock-based awards

   3            3  

Other comprehensive income, net of income taxes

           1    1  
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance at March 23, 2016

  $3,838   $636   $(35 $4,439  
  

 

 

  

 

 

  

 

 

  

 

 

 

Successor

     

Balance at March 24, 2016(b)

  $7,200   $   $   $7,200  

Net loss

       (309      (309

Distribution to member

   (235          (235

Distribution of net retirement benefit obligation to member

   45            45  

Assumption of member purchase liability(c)

   (29          (29
  

 

 

  

 

 

  

 

 

  

 

 

 

Balance at March 31, 2016

  $6,981   $(309 $   $6,672  
  

 

 

  

 

 

  

 

 

  

 

 

 

(a)

At March 23, 2016 and December 31, 2015, PHI’s (predecessor) shareholders’ equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively.

(b)

The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger.

(c)

The total purchase price consideration for the PHI Merger included $29 million for cash paid for PHI stock-based compensation awards. See Note 4—Mergers, Acquisitions and Dispositions for further information. The $29 million of cash was paid by PHI.

See the Combined Notes to Consolidated Financial Statements

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

   Three Months Ended March 31, 
(In millions)      2016          2015     

Operating revenues

   

Electric operating revenues

  $550   $544  

Operating revenues from affiliates

   1    1  
  

 

 

  

 

 

 

Total operating revenues

   551    545  
  

 

 

  

 

 

 

Operating expenses

   

Purchased power

   191    211  

Purchased power and fuel from affiliates

   6      

Operating and maintenance

   288    112  

Operating and maintenance from affiliates

   2    1  

Depreciation and amortization

   75    62  

Taxes other than income

   94    96  
  

 

 

  

 

 

 

Total operating expenses

   656    482  
  

 

 

  

 

 

 

Operating (loss) income

   (105  63  
  

 

 

  

 

 

 

Other income and (deductions)

   

Interest expense, net

   (37  (30

Other, net

   9    5  
  

 

 

  

 

 

 

Total other income and (deductions)

   (28  (25
  

 

 

  

 

 

 

(Loss) Income before income taxes

   (133  38  

Income taxes

   (25  12  
  

 

 

  

 

 

 

Net (loss) income attributable to common shareholder

  $(108 $26  
  

 

 

  

 

 

 

Comprehensive (loss) income

  $(108 $26  
  

 

 

  

 

 

 

See the Combined Notes to Financial Statements

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

   Three Months Ended March 31, 
(In millions)      2016          2015     

Cash flows from operating activities

   

Net (loss) income

  $(108 $26  

Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:

   

Depreciation and amortization

   75    62  

Deferred income taxes and amortization of investment tax credits

   (31  12  

Other non-cash operating activities

   153    23  

Changes in assets and liabilities:

   

Accounts receivable

   (24  (93

Receivables from and payables to affiliates, net

   55    21  

Inventories

   1    (6

Accounts payable and accrued expenses

   (4  6  

Income taxes

   151      

Pension and non-pension postretirement benefit contributions

   (1    

Other assets and liabilities

   (9  (18
  

 

 

  

 

 

 

Net cash flows provided by operating activities

   258    33  
  

 

 

  

 

 

 

Cash flows from investing activities

   

Capital expenditures

   (109  (119

Purchases of investments

   (31    

Changes in restricted cash

   2    3  

Other investing activities

   2    3  
  

 

 

  

 

 

 

Net cash flows used in investing activities

   (136  (113
  

 

 

  

 

 

 

Cash flows from financing activities

   

Changes in short-term borrowings

   (64  (104

Issuance of long-term debt

       208  

Retirement of long-term debt

       (12

Dividends paid on common stock

   (39    

Contribution from parent

       112  

Other financing activities

       (4
  

 

 

  

 

 

 

Net cash flows (used in) provided by financing activities

   (103  200  
  

 

 

  

 

 

 

Increase in cash and cash equivalents

   19    120  

Cash and cash equivalents at beginning of period

   5    6  
  

 

 

  

 

 

 

Cash and cash equivalents at end of period

  $24   $126  
  

 

 

  

 

 

 

See the Combined Notes to Financial Statements

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)  March 31,
2016
   December 31,
2015
 
   (Unaudited)     
ASSETS    

Current assets

    

Cash and cash equivalents

  $24    $5  

Restricted cash and cash equivalents

        2  

Accounts receivable, net

    

Customer

   240     230  

Other

   117     261  

Inventories, net

   65     67  

Regulatory assets

   133     140  

Assets held for sale

   4       

Other

   22     21  
  

 

 

   

 

 

 

Total current assets

   605     726  
  

 

 

   

 

 

 

Property, plant and equipment, net

   5,225     5,162  

Deferred debits and other assets

    

Regulatory assets

   663     661  

Investments

   99     68  

Prepaid pension asset

   280     287  

Other

   5     4  
  

 

 

   

 

 

 

Total deferred debits and other assets

   1,047     1,020  
  

 

 

   

 

 

 

Total assets

  $6,877    $6,908  
  

 

 

   

 

 

 

See the Combined Notes to Financial Statements

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)  March 31,
2016
   December 31,
2015
 
   (Unaudited)     
LIABILITIES AND SHAREHOLDER’S EQUITY    

Current liabilities

    

Short-term borrowings

  $    $64  

Long-term debt due within one year

   11     11  

Accounts payable

   129     145  

Accrued expenses

   138     119  

Payables to affiliates

   85     30  

Customer deposits

   51     46  

Regulatory liabilities

   26     15  

Merger related obligation

   49       

Other

   20     25  
  

 

 

   

 

 

 

Total current liabilities

   509     455  
  

 

 

   

 

 

 

Long-term debt

   2,341     2,340  

Deferred credits and other liabilities

    

Regulatory liabilities

   29     29  

Deferred income taxes and unamortized investment tax credits

   1,695     1,723  

Non-pension postretirement benefit obligations

   49     49  

Other

   161     72  
  

 

 

   

 

 

 

Total deferred credits and other liabilities

   1,934     1,873  
  

 

 

   

 

 

 

Total liabilities

   4,784     4,668  
  

 

 

   

 

 

 

Commitments and contingencies

    

Shareholder’s equity

    

Common stock

   1,122     1,122  

Retained earnings

   971     1,118  
  

 

 

   

 

 

 

Total shareholder’s equity

   2,093     2,240  
  

 

 

   

 

 

 

Total liabilities and shareholder’s equity

  $6,877    $6,908  
  

 

 

   

 

 

 

See the Combined Notes to Financial Statements

POTOMAC ELECTRIC POWER COMPANY

STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

(In millions)  Common
Stock
   Retained
Earnings
  Total
Shareholder’s
Equity
 

Balance, December 31, 2015

  $1,122    $1,118   $2,240  

Net loss

        (108  (108

Common stock dividends

        (39  (39
  

 

 

   

 

 

  

 

 

 

Balance, March 31, 2016

  $1,122    $971   $2,093  
  

 

 

   

 

 

  

 

 

 

See the Combined Notes to Financial Statements

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

   Three Months Ended
March  31,
 
(In millions)      2016          2015     

Operating revenues

   

Electric operating revenues

  $301   $333  

Natural gas operating revenues

   59    86  

Operating revenues from affiliates

   2    2  
  

 

 

  

 

 

 

Total operating revenues

   362    421  
  

 

 

  

 

 

 

Operating expenses

   

Purchased power

   147    178  

Purchased fuel

   25    47  

Purchased power from affiliate

   4      

Operating and maintenance

   204    81  

Depreciation, amortization and accretion

   39    39  

Taxes other than income

   15    13  
  

 

 

  

 

 

 

Total operating expenses

   434    358  
  

 

 

  

 

 

 

Operating (loss) income

   (72 ��63  
  

 

 

  

 

 

 

Other income and (deductions)

   

Interest expense, net

   (12  (12

Other, net

   3    2  
  

 

 

  

 

 

 

Total other income and (deductions)

   (9  (10
  

 

 

  

 

 

 

(Loss) Income before income taxes

   (81  53  

Income taxes

   (9  21  
  

 

 

  

 

 

 

Net (loss) income attributable to common shareholder

  $(72 $32  
  

 

 

  

 

 

 

Comprehensive (loss) income

  $(72 $32  
  

 

 

  

 

 

 

See the Combined Notes to Financial Statements

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

   Three Months Ended
March  31,
 
(In millions)      2016          2015     

Cash flows from operating activities

   

Net (loss) income

  $(72 $32  

Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:

   

Depreciation, amortization and accretion

   39    39  

Deferred income taxes and amortization of investment tax credits

   (4  21  

Other non-cash operating activities

   118    12  

Changes in assets and liabilities:

   

Accounts receivable

   4    (82

Receivables from and payables to affiliates, net

   20    4  

Inventories

   1    5  

Accounts payable and accrued expenses

   (3  12  

Collateral received

   1      

Income taxes

   52      

Other assets and liabilities

   (9  14  
  

 

 

  

 

 

 

Net cash flows provided by operating activities

   147    57  
  

 

 

  

 

 

 

Cash flows from investing activities

   

Capital expenditures

   (81  (68

Changes in restricted cash

       5  

Other investing activities

       2  
  

 

 

  

 

 

 

Net cash flows used in investing activities

   (81  (61
  

 

 

  

 

 

 

Cash flows from financing activities

   

Changes in short-term borrowings

   (30  69  

Dividends paid on common stock

   (38  (62
  

 

 

  

 

 

 

Net cash flows (used in) provided by financing activities

   (68  7  
  

 

 

  

 

 

 

(Decrease) Increase in cash and cash equivalents

   (2  3  

Cash and cash equivalents at beginning of period

   5    4  
  

 

 

  

 

 

 

Cash and cash equivalents at end of period

  $3   $7  
  

 

 

  

 

 

 

See the Combined Notes to Financial Statements

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)  March 31,
2016
   December 31,
2015
 
   (Unaudited)     
ASSETS    

Current assets

    

Cash and cash equivalents

  $3    $5  

Accounts receivable, net

    

Customer

   149     154  

Other

   40     96  

Inventories, net

    

Gas held in storage

   4     8  

Materials and supplies

   34     32  

Regulatory assets

   67     72  

Other

   22     21  
  

 

 

   

 

 

 

Total current assets

   319     388  
  

 

 

   

 

 

 

Property, plant and equipment, net

   3,132     3,070  

Deferred debits and other assets

    

Regulatory assets

   295     299  

Goodwill

   8     8  

Prepaid pension asset

   197     202  

Other

   8     2  
  

 

 

   

 

 

 

Total deferred debits and other assets

   508     511  
  

 

 

   

 

 

 

Total assets

  $3,959    $3,969  
  

 

 

   

 

 

 

See the Combined Notes to Financial Statements

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)  March 31,
2016
   December 31,
2015
 
   (Unaudited)     
LIABILITIES AND SHAREHOLDER’S EQUITY    

Current liabilities

    

Short-term borrowings

  $75    $105  

Long-term debt due within one year

   218     204  

Accounts payable

   100     109  

Accrued expenses

   44     31  

Payables to affiliates

   42     20  

Customer deposits

   35     31  

Regulatory liabilities

   57     49  

Merger related obligation

   76       

Other

   9     15  
  

 

 

   

 

 

 

Total current liabilities

   656     564  
  

 

 

   

 

 

 

Long-term debt

   1,047     1,061  

Deferred credits and other liabilities

    

Regulatory liabilities

   109     111  

Deferred income taxes and unamortized investment tax credits

   939     945  

Non-pension postretirement benefit obligations

   21     19  

Other

   60     32  
  

 

 

   

 

 

 

Total deferred credits and other liabilities

   1,129     1,107  
  

 

 

   

 

 

 

Total liabilities

   2,832     2,732  
  

 

 

   

 

 

 

Commitments and contingencies

    

Shareholder’s equity

    

Common stock

   612     612  

Retained earnings

   515     625  
  

 

 

   

 

 

 

Total shareholder’s equity

   1,127     1,237  
  

 

 

   

 

 

 

Total liabilities and shareholder’s equity

  $3,959    $3,969  
  

 

 

   

 

 

 

See the Combined Notes to Financial Statements

DELMARVA POWER & LIGHT COMPANY

STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

(In millions)  Common
Stock
   Retained
Earnings
  Total
Shareholder’s
Equity
 

Balance, December 31, 2015

  $612    $625   $1,237  

Net loss

        (72  (72

Common stock dividends

        (38  (38
  

 

 

   

 

 

  

 

 

 

Balance, March 31, 2016

  $612    $515   $1,127  
  

 

 

   

 

 

  

 

 

 

See the Combined Notes to Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

   Three Months Ended March 31, 
(In millions)      2016          2015     

Operating revenues

   

Electric operating revenues

  $290   $333  

Operating revenues from affiliates

   1    1  
  

 

 

  

 

 

 

Total operating revenues

   291    334  
  

 

 

  

 

 

 

Operating expenses

   

Purchased power

   157    191  

Purchased power from affiliates

   1      

Operating and maintenance

   211    68  

Operating and maintenance from affiliates

   1    1  

Depreciation, amortization and accretion

   40    43  

Taxes other than income

   2    2  
  

 

 

  

 

 

 

Total operating expenses

   412    305  
  

 

 

  

 

 

 

Operating (loss) income

   (121  29  

Other income and (deductions)

   

Interest expense, net

   (16  (16

Other, net

   4    1  
  

 

 

  

 

 

 

Total other income and (deductions)

   (12  (15
  

 

 

  

 

 

 

(Loss) Income before income taxes

   (133  14  

Income taxes

   (33  5  
  

 

 

  

 

 

 

Net (loss) income attributable to common shareholder

  $(100 $9  
  

 

 

  

 

 

 

Comprehensive (loss) income

  $(100 $9  
  

 

 

  

 

 

 

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

   Three Months Ended
March 31,
 
(In millions)      2016          2015     

Cash flows from operating activities

   

Net (loss) income

  $(100 $9  

Adjustments to reconcile net (loss) income to net cash from operating activities:

   

Depreciation, amortization and accretion

   40    43  

Deferred income taxes and amortization of investment tax credits

   (33  5  

Other non-cash operating activities

   132    8  

Changes in assets and liabilities:

   

Accounts receivable

   5    (44

Receivables from and payables to affiliates, net

   20    2  

Inventories

   (2  (1

Accounts payable and accrued expenses

   19    21  

Income taxes

   168      

Other assets and liabilities

   (3  20  
  

 

 

  

 

 

 

Net cash flows provided by operating activities

   246    63  
  

 

 

  

 

 

 

Cash flows from investing activities

   

Capital expenditures

   (101  (54

Changes in restricted cash

   1      

Other investing activities

       1  
  

 

 

  

 

 

 

Net cash flows used in investing activities

   (100  (53
  

 

 

  

 

 

 

Cash flows from financing activities

   

Changes in short-term borrowings

   (5  16  

Retirement of long-term debt

   (11  (10

Dividends paid on common stock

   (11  (12
  

 

 

  

 

 

 

Net cash flows used in financing activities

   (27  (6
  

 

 

  

 

 

 

Increase in cash and cash equivalents

   119    4  

Cash and cash equivalents at beginning of period

   3    2  
  

 

 

  

 

 

 

Cash and cash equivalents at end of period

  $122   $6  
  

 

 

  

 

 

 

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)  March 31,
2016
   December 31,
2015
 
   (Unaudited)     
ASSETS    

Current assets

    

Cash and cash equivalents

  $122    $3  

Restricted cash and cash equivalents

   11     12  

Accounts receivable, net

    

Customer

   146     156  

Other

   74     242  

Inventories, net

   24     23  

Regulatory assets

   95     98  

Other

   13     12  
  

 

 

   

 

 

 

Total current assets

   485     546  
  

 

 

   

 

 

 

Property, plant and equipment, net

   2,384     2,322  

Deferred debits and other assets

    

Regulatory assets

   419     414  

Long-term note receivable

   4     4  

Prepaid pension asset

   79     82  

Other

   22     19  
  

 

 

   

 

 

 

Total deferred debits and other assets

   524     519  
  

 

 

   

 

 

 

Total assets(a)

  $3,393    $3,387  
  

 

 

   

 

 

 

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)  March 31,
2016
   December 31,
2015
 
   (Unaudited)     
LIABILITIES AND SHAREHOLDER’S EQUITY    

Current liabilities

    

Short-term borrowings

  $    $5  

Long-term debt due within one year

   47     48  

Accounts payable

   101     96  

Accrued expenses

   77     70  

Payables to affiliates

   36     16  

Customer deposits

   35     30  

Regulatory liabilities

   22     18  

Merger related obligation

   110       

Other

   16     14  
  

 

 

   

 

 

 

Total current liabilities

   444     297  
  

 

 

   

 

 

 

Long-term debt

   1,144     1,153  

Deferred credits and other liabilities

    

Deferred income taxes and unamortized investment tax credits

   854     885  

Non-pension postretirement benefit obligations

   35     33  

Regulatory liabilities

   5     7  

Other

   22     12  
  

 

 

   

 

 

 

Total deferred credits and other liabilities

   916     937  
  

 

 

   

 

 

 

Total liabilities(a)

   2,504     2,387  
  

 

 

   

 

 

 

Commitments and contingencies

    

Shareholder’s equity

    

Common stock

   773     773  

Retained earnings

   116     227  
  

 

 

   

 

 

 

Total shareholder’s equity

   889     1,000  
  

 

 

   

 

 

 

Total liabilities and shareholder’s equity

  $3,393    $3,387  
  

 

 

   

 

 

 

(a)

ACE’s consolidated total assets include $29 million and $30 million at March 31, 2016 and December 31, 2015, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $161 million and $172 million at March 31, 2016 and December 31, 2015, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 3 — Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

(In millions)  Common
Stock
   Retained
Earnings
  Total
Shareholder’s
Equity
 

Balance, December 31, 2015

  $773    $227   $1,000  

Net loss

        (100  (100

Common stock dividends

        (11  (11
  

 

 

   

 

 

  

 

 

 

Balance, March 31, 2016

  $773    $116   $889  
  

 

 

   

 

 

  

 

 

 

See the Combined Notes to Consolidated Financial Statements

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Index to Combined Notes toTo Consolidated Financial Statements

The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the registrantsRegistrants to which the footnotes apply:

Applicable Notes

 

Registrant

 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21  1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 

Exelon Corporation

  .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .  

Exelon Generation Company, LLC

  .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .      .     .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .    .     .    .    .  

Commonwealth Edison Company

  .    .    .     .       .    .    .    .     .    .       .     .    .    .    .    .    .      .    .    .    .     .    .       .    .    .  

PECO Energy Company

  .    .    .     .       .    .    .    .     .    .    .      .     .    .    .    .    .    .      .    .    .    .     .    .    .      .    .    .  

Baltimore Gas And Electric Company

  .    .    .     .       .    .    .    .     .    .       .     .  

Baltimore Gas and Electric Company

  .    .    .    .    .      .    .    .    .     .    .       .    .    .  

Pepco Holdings LLC

  .    .    .    .    .      .    .    .    .     .    .    .    .     .    .    .  

Potomac Electric Power Company

  .    .    .    .    .      .    .    .    .     .    .       .    .    .  

Delmarva Power & Light Company

  .    .    .    .    .      .    .    .    .     .    .       .    .    .  

Atlantic City Electric Company

  .    .    .    .    .      .    .    .    .     .    .       .    .    .  

1.     BasisSignificant Accounting Policies (All Registrants)

Description of Presentation (Exelon, Generation, ComEd, PECO and BGE)Business (All Registrants)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and transmission businesses. Prior to March 23, 2016, Exelon’s principal, wholly owned subsidiaries included Generation, ComEd, PECO and BGE. On March 23, 2016, in conjunction with the Amended and Restated Agreement and Plan of Merger (the PHI Merger Agreement), Purple Acquisition Corp, a wholly owned subsidiary of Exelon, merged with and into PHI, with PHI continuing as the surviving entity as a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further information regarding the merger transaction.

The energy generation business includes:

 

  

Generation:    PhysicalGeneration, physical delivery and marketing of ownedpower across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and contracted electric generation capacitynatural gas to both wholesale and provision ofretail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities.activities (Upstream). Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions.

The energy delivery businesses include:

 

  

ComEd:    Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in northern Illinois, including the City of Chicago.

 

  

PECO:    Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

 

  

BGE:    Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in central Maryland, including the City of Baltimore.

Each

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Pepco:    Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland.

DPL:    Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

ACE:    Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southern New Jersey.

Basis of Presentation (All Registrants)

Pursuant to the acquisition of PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which requires the assets acquired and liabilities assumed by Exelon to be reported in Exelon’s financial statements at fair value, with any excess of the Registrant’spurchase price over the fair value of net assets acquired reported as goodwill. Exelon has pushed-down the application of the acquisition method of accounting to the consolidated financial statements includesof PHI such that the accountsassets and liabilities of its subsidiaries. All intercompany transactions havePHI are similarly recorded at their respective fair values, and goodwill has been eliminated. As a resultestablished as of the Registrants’ 2014 divestitureacquisition date. Accordingly, the consolidated financial statements of certain unconsolidated affiliates considered integral to their operationsPHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the consolidationfinancial positions and the results of CENG during 2014, all Equityoperations of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly-owned subsidiary utility registrants, Pepco, DPL and ACE.

For financial statement purposes, beginning on March 24, 2016, disclosures that had solely related to PHI, Pepco, DPL or ACE activities now also apply to Exelon, unless otherwise noted. When appropriate, Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are named specifically for their related activities and disclosures.

Certain prior year amounts in earnings (losses) from unconsolidated affiliates have been presented below Income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income startingConsolidated Balance Sheets and Consolidated Statements of Cash Flows of PHI, Pepco, DPL and ACE have been reclassified to conform the presentation of these amounts to the current period presentation in Exelon’s financial statements. Most significantly for PHI, Pepco, DPL and ACE, current regulatory assets and liabilities have been presented separately from the first quarternon-current portions in each respective Consolidated Balance Sheet where recovery or refund is expected within the next 12 months. Additionally, for PHI, Pepco, DPL and ACE, the removal cost within Accumulated depreciation was reclassified to the Regulatory liability or Regulatory asset account to align with Exelon’s presentation. The reclassifications were not considered errors for PHI, Pepco, DPL or ACE.

In its December 31, 2015 Form 10-K, Exelon revised the presentation on the Statements of 2015.

ForOperations and Comprehensive Income for PECO and BGE to reflect separately operating revenues from the three months ended September 30, 2015, Generation recorded a $52 million (pre-tax) correcting adjustmentsale of electricity and operating revenues from the sale of natural gas, as well as, to decrease mark-to-market income level 3 derivative contract valuations,reflect separately purchased power expense and purchased fuel expense within the operating expenses section of which $12 million (pre-tax) was originally recorded during 2014the Statement of Operations and $40 million (pre-tax) was originally recorded duringComprehensive Income. Further, Exelon revised the firstpresentation from Total operating revenues to “Rate-regulated utility revenues” and “Competitive businesses revenues” on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. Similarly, Exelon has separately presented Rate-regulated utility purchased power and fuel expense and Competitive businesses purchased power and fuel expense on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. The reclassifications described herein were made for presentation purposes and did not affect any of the Registrants’ total operating revenues or net income.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

and secondACE Basic Generation Service Recovery Mechanism

ACE has a recovery mechanism for purchased power costs associated with BGS. ACE records a deferred energy supply costs regulatory asset or regulatory liability for under or over-recovered costs that are expected to be recovered from or refunded by ACE customers, respectively. In the first quarter of 2015. Exelon2016, ACE changed its method of accounting for determining under or over-recovered costs in this recovery mechanism to now include unbilled revenues in the determination of under or over-recovered costs. ACE believes this change is preferable as it better reflects the economic impacts of dollar-for-dollar cost recovery mechanisms. ACE applied the change retrospectively. The impact of the change was a $12 million reduction to ACE’s opening Retained earnings as of January 1, 2014 with a corresponding reduction to Regulatory assets. The impact of the change on Net income attributable to common shareholder is an increase of $1 million and Generation have concluded that this correcting adjustment is not material to their respective results of operations$5 million for the three and nine months ended September 30,March 31, 2016 and March 31, 2015, or cash flowsrespectively.

Classification of Interest on Uncertain Tax Positions

In the first quarter of 2016 PHI, Pepco, DPL and ACE changed their accounting principle for classification of interest on uncertain tax positions. PHI, Pepco, DPL and ACE have reclassified interest on uncertain tax positions as interest expense from income tax expense in the Consolidated Statements of Operations and Comprehensive Income. GAAP does not address the preferability of one acceptable method of accounting over the other for the nineclassification of interest on uncertain tax positions. However, PHI, Pepco, DPL, and ACE believe this change is preferable for comparability of their financial statements with the financial statements of the other Registrants in the combined filing, for consistency with FERC classification, and for a more appropriate representation of the effective tax rate as they manage the settlement of uncertain tax positions and interest expense separately. PHI, Pepco, DPL, and ACE applied the change retrospectively.

The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the three months ended September 30, 2015 or any prior period presented. ExelonMarch 31, 2016 is less than $1 million for each of PHI Successor, PHI Predecessor and Generation do not expect this correcting adjustment to have a material impact on their respective resultsDPL, and $1 million for each of operations or cash flowsPepco and ACE. The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the yearthree months ended March 31, 2015 is less than $1 million for PHI, Pepco, DPL and ACE, respectively. The reclassification amount is more significant for the year-ended December 31, 2015.

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

The accompanying consolidated financial statements as of September 30,March 31, 2016 and 2015 and 2014 and for the ninethree months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 20142015 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2015.2016. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Combined Notes to Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 20142015 Form 10-K Reports.

2.    New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)

The following recently issued accounting standard was effective for the Registrants during 2015.

Application of Normal Purchases Normal Sales Exception to Power Contracts in Nodal Energy Markets

In August 2015, the FASB issued authoritative guidance addressing the ability of entities to elect the normal purchase normal sales (NPNS) scope exception when the contract for the purchase or sale of electricity on a forward basis is delivered to a nodal energy market or transmitted through a nodal energy market. The NPNS scope exception allows entities to treat certain contracts that qualify as derivatives as contracts that do not require recognition at fair value. The guidance specifies that the use of locational marginal pricing by an independent system operator in such transactions does not constitute net settlement of a contract for the purchase or sale of electricity, even in scenarios in which legal title to the associated electricity is conveyed to the independent system operator during transmission. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the NPNS scope exception. If the physical delivery criterion is met, along with all of the other criteria of the NPNS scope exception, an entity may elect to designate that contract as NPNS. The guidance is effective upon issuance and should be applied prospectively. The adoption of this guidance had no impact on the Registrants’ financial positions, results of operations, cash flows and disclosures.

The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of the Registrants.

Simplifying the Accounting for Measurement-Period Adjustments

In September 2015, the FASB issued authoritative guidance that requires an acquirer in a business combination to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined and to record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

2.    New Accounting Pronouncements (All Registrants)

Exelon has identified the acquisition date.following new accounting standards that have been recently adopted.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts where collectability is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. In August 2015, the FASB issued an amendment to provide a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017, as well as an option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard. In March 2016, the FASB issued final amendments to clarify the implementation guidance for principal versus agent considerations, identifying performance obligations and the accounting for licenses of intellectual property. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of these updates.

Leases

In February 2016, the FASB issued authoritative guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The guidance requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only financing type lease liabilities (capital leases) are recognized in the balance sheet. This is expected to require significant changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. The accounting applied by a lessor is largely unchanged from that applied under current GAAP. The standard is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share

In May 2015, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. The guidance is effective for periodsthe Registrants for fiscal years beginning after December 15, 2015. The Registrants adopted the standard in the first quarter of 2016, and applied the guidance retrospectively to all prior periods presented. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. See Note 8 — Fair Value of Financial Assets and Liabilities for the disclosure impacts.

Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either operate the software on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. The Registrants prospectively adopted the standard in the first quarter of 2016. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the VIE assessment of limited partnerships, (2) amends the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity, and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance became effective for the Registrants January 1, 2016. The Registrants adopted the standard in the first quarter of 2016. The Registrants have evaluated the standard and have not identified any changes to consolidation conclusions as a result of the new guidance. Based on the analysis completed, additional entities were considered VIEs. See Note 3 — Variable Interest Entities for the disclosure impacts.

The following recently issued accounting standards are not yet required to be reflected in the consolidated financial statements of the Registrants.

Improvements to Employee Share-Based Payment Accounting

In March 2016, the FASB issued authoritative guidance intended to simplify various aspects to how share-based payment awards to employees are accounted for and presented in the financial statements. The new guidance eliminates additional paid-in capital pools and requires excess tax benefits and tax deficiencies to be recorded in the Statement of Operations and Comprehensive Income. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted if all provisions are adopted within the same period. The guidance is required to be applied prospectively to adjustments to provisional amounts that occur afteron either a prospective, modified retrospective, or retrospective

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

basis depending on the effective date with earlier application permitted for financial statements that have not been issued.provisions applied. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the standardguidance.

Simplifying the Transition to the Equity Method of Accounting

In March 2016, the FASB issued authoritative guidance eliminating the requirement to retroactively adopt the equity method of accounting as a result of an increase in the fourth quarterlevel ownership or degree of 2015.influence of an existing investment. The guidance now requires an investor to add the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for the equity method of accounting. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption ofpermitted. The Registrants do not expect that this guidance will have noa significant impact on the Registrants’ financial positions, resultstheir Consolidated Balance Sheets, Consolidated Statements of operations, cash flowsOperations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued authoritative guidance which clarifies that a change in the counterparty of a derivative contract does not, in and of itself, require dedesignation of that hedge accounting relationship as long as all of the other hedge accounting criteria are met. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. Entities have the option to adopt this standard on a prospective basis to new derivative contract novations or on a modified retrospective basis. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the transition method and the potential to early adopt the guidance.

Contingent Put and Call Options in Debt Instruments

In March 2016, the FASB issued authoritative guidance which simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The guidance clarifies that a contingent put or call option embedded in a debt instrument would be evaluated for possible separate accounting as a derivative instrument without regard to the nature of the exercise contingency. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued authoritative guidance which (i) requires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Registrants are currently assessing the impacts this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the potential to early adopt the guidance.

Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share

In May 2015, FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all prior periods presented. The Registrants are currently assessing the impacts this guidance may have on their disclosures as well as the potential to early adopt the guidance. There will be no impact to their financial position, results of operations or cash flows.

Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either run the software on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted. The guidance can be applied retrospectively to each prior reporting period presented or prospectively to arrangements entered into, or materially modified, after the effective date. The Registrants do not expect that this guidance will have a significant impact on their financial positions, resultsConsolidated Balance Sheets, Consolidated Statements of operations, cash flowsOperations and disclosures. The Registrants expect to apply the standard prospectively to arrangements entered into, or materially modified, after the standard becomes effective for the Registrants on January 1, 2016. The Registrants do not plan to early adopt the standard.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Simplifying the PresentationComprehensive Income, Consolidated Statements of Debt Issuance Costs

In April 2015, the FASB issued authoritative guidance that changes the presentation of debt issuance costs in financial statements. The new guidance requires entities to present such costs in the balance sheet as a direct reduction to the related debt liability rather than as a deferred cost (i.e., an asset) as required by current guidance. The new standard does not change the recognition or measurement of debt issuance costs. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The guidance is required to be applied retrospectively to all prior periods presented.Cash Flows and disclosures. The Registrants are currently assessing the impact this guidance may have on their financial positions and disclosures. The standard will not impact the results of operations and cash flows of the Registrants. The Registrants expect to complete their assessment by the fourth quarter of 2015 and early adopt the standard at that time.

In August 2015, the FASB issued clarifying authoritative guidance for debt issuance costs incurred in connection with line-of-credit arrangements as such costs were not addressed within the guidance simplifying the presentation of debt issuance costs issued in April 2015. The guidance clarifies that an entity can defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The adoption of this guidance will have no impact on the Registrants’ financial positions, results of operations, cash flows and disclosures.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the assessment of limited partnerships as VIEs, (2) amends the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance is effective for the Registrants for the first interim period beginning on or after December 15, 2015. Early adoption is permitted. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impact this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. The Registrants do not planpotential to early adopt the standard.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new guidance replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

method). The Registrants are currently assessing the impacts this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. In August 2015, the FASB issued an amendment to provide a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017, as well as an option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard.

3.    Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.

At September 30, 2015 and DecemberMarch 31, 2014,2016, Exelon, Generation, BGE, PHI and BGEACE collectively consolidated seven and sixnine VIEs or VIE groups respectively, for which the applicable Registrant was the primary beneficiary beneficiary. At December 31, 2015, Exelon, Generation and BGE collectively had seven consolidated VIEs or VIE groups and PHI and ACE collectively had one consolidated VIE ((see Consolidated Variable Interest Entities below). As of September 30, 2015March 31, 2016 and December 31, 2014, the Registrants2015, Exelon and Generation collectively had significant interests in eightnine and sixeight other VIEs, respectively, for which the Registrants doapplicable Registrant does not have the power to direct the entities’ activities and, accordingly, werewas not the primary beneficiary (see(see Unconsolidated Variable Interest Entities below).

During the second quarter of 2015 Generation added a new group of consolidated VIEs named “a group of companies formed by Generation to build, own, and operate other generating facilities.” The new group is comprised of a biomass fueled, combined heat and power facility and a backup generator company for which Generation is the primary beneficiary. Generation provides parental guarantees for up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract for Albany Green Energy, LLC (see Note 11 — Debt and Credit Agreements for additional details).

Consolidated Variable Interest Entities

Exelon,In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute a total of $250 million of equity incrementally from inception through December 2016 in proportion to their ownership interests, which equates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 18 — Commitments and Contingencies for more details). The investment in the distributed energy company was

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

evaluated, and it was determined to be a VIE for which Generation is not the primary beneficiary (see additional details in the Unconsolidated Variable Interest Entities section below). As of December 31, 2015, Generation consolidated 2015 ESA Investco, LLC under the voting interest model. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, 2015 ESA Investco, LLC meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. (For additional details related to the new consolidation guidance, see Note 2 — New Accounting Pronouncements.) Under VIE guidance, Generation is the primary beneficiary; therefore, the entity continues to be consolidated.

Exelon’s, Generation’s, BGE’s, PHI’s and ACE’s consolidated VIEs consist of:

 

BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property,

aA retail gas group formed by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier,

 

a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities,

 

several wind project companies designed by Generation to develop, construct and operate wind generation facilities,

 

a group of companies formed by Generation to build, own and operate other generating facilities,

 

certain retail power and gas companies for which Generation is the sole supplier of energy,

CENG,

2015 ESA Investco, LLC,

BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property, and

 

CENG.ATF, a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.

As of September 30, 2015March 31, 2016 and December 31, 2014,2015, ComEd, PECO, Pepco and PECODPL do not have any material consolidated VIEs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

As of September 30, 2015March 31, 2016 and December 31, 2014,2015, Exelon, Generation, BGE, PHI and BGEACE provided the following support to their respective consolidated VIEs:

In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three and nine months ended September 30, 2015, BGE remitted $21 million and $63 million to BondCo, respectively. During the three and nine months ended September 30, 2014, BGE remitted $21 million and $63 million to BondCo, respectively.

 

Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance of the solar and wind power facilities and there is limited recourse to Generation related to the Antelope Valley project.certain solar and wind entities.

 

Generation and Exelon, where indicated, provide the following support to CENG (see Note 65 — Investment in Constellation Energy Nuclear Group, LLC and Note 2526 — Related Party Transactions of the Exelon 20142015 Form 10-K for additional information regarding Generation’s and Exelon’s transactions with CENG):

 

under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF, Inc. (EDFI) (a subsidiary of EDF),

 

under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs have been suspended during the term of the expected Reliability Support Services Agreement (RSSA). Ginna originally entered into an agreement with Rochester Gas and Electric Corporation (RG&E) on February 13, 2015; however, final terms and conditions are currently under negotiation. The obligations under the RSSA are expected to commence retroactive back to April 1, 2015 and run through March 31, 2017 (see Note 5 — Regulatory Matters for additional details),

 

Generation provided a $400 million loan to CENG. As of September 30, 2015,March 31, 2016, the remaining obligation is $296$304 million, including accrued interest, which reflects the principal payment made in January 2015, (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2014 Form 10-K for additional details),

 

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 1918 — Commitments and Contingencies for more details),

 

in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid in 2014 through 2016. As of September 30, 2015,March 31, 2016, the remaining obligation is approximately $1 million,immaterial,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Generation and EDFIEDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, (see Note 19 — Commitments and Contingencies for more details),

 

Generation provides a guarantee of approximately $7 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDFIEDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,

 

Generation and EDFIEDF are the members-insured with Nuclear Electric Insurance Limited (NEIL) and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 1918 — Commitments and Contingencies for more details), and

 

Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

 

Generation provides approximately $11$14 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy, andenergy.

 

Generation provides a $75 million parental guarantee to thea third-party gas supplier and provides limited recourse to other third-party gas suppliers and customers in support of its retail gas group.

Generation provides operating and capital funding to the other generating facilities for ongoing construction, operations and maintenance and provides a parental guarantee of up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract in support of one of its other generating facilities.

In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three months ended March 31, 2016 and 2015, BGE remitted $20 million and $21 million to BondCo, respectively.

In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three months ended March 31, 2016 and 2015, ACE transferred $14 million and $13 million to ATF, respectively.

For each of the consolidated VIEs, except as otherwise noted:

 

the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;

 

Exelon, Generation, BGE, PHI and BGEACE did not provide any additional material financial support to the VIEs;

 

Exelon, Generation, BGE, PHI and BGEACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and

 

the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, BGE’s, PHI’s or BGE’sACE’s general credit.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in Exelon’s, Generation’s, and BGE’sthe Registrants’ consolidated financial statements at September 30, 2015March 31, 2016 and December 31, 20142015 are as follows:

 

 March 31, 2016    December 31, 2015 
  September 30, 2015   December 31, 2014        Successor            Predecessor   
  Exelon(a)   Generation   BGE   Exelon(a)   Generation   BGE  Exelon(a)(b) Generation BGE PHI(b) ACE    Exelon(a) Generation BGE PHI ACE 

Current assets

  $1,108    $1,057    $46    $1,271    $1,242    $21   $928   $860   $44   $22   $11     $909   $881   $23   $12   $12  

Noncurrent assets

   7,736     7,728     3     7,580     7,566     3    8,047    7,996    3    46    18      8,009    8,004    3    18    18  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total assets

  $8,844    $8,785    $49    $8,851    $8,808    $24   $8,975   $8,856   $47   $68   $29     $8,918   $8,885   $26   $30   $30  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Current liabilities

  $494    $408    $81    $611    $526    $77   $544   $400   $83    58   $47     $473   $387   $81   $48   $48  

Noncurrent liabilities

   2,859     2,773     81     2,730     2,600     120    3,050    2,865    41    142    114      2,927    2,884    41    124    124  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total liabilities

  $3,353    $3,181    $162    $3,341    $3,126    $197   $3,594   $3,265   $124   $200   $161     $3,400   $3,271   $122   $172   $172  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

 

(a)

Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

(b)

Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Assets and Liabilities of Consolidated VIEs

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of September 30, 2015March 31, 2016 and December 31, 2014,2015, these assets and liabilities primarily consisted of the following:

 

 March 31, 2016    December 31, 2015 
  September 30, 2015   December 31, 2014        Successor            Predecessor   
  Exelon   Generation   BGE   Exelon   Generation   BGE  Exelon(a)(b) Generation BGE PHI(b) ACE    Exelon(a) Generation BGE PHI ACE 

Cash and cash equivalents

  $330    $330    $    $392    $392    $   $145   $145   $   $   $     $164   $164   $   $   $  

Restricted cash

   193     146     46     117     96     21    117    62    44    11    11      100    77    23    12    12  

Accounts receivable, net

                        

Customer

   186     186          297     297         231    231                  219    219              

Other

   32     32          57     57         28    28                  43    43              

Mark-to-market derivatives assets

   116     116          171     171         120    120                  140    140              

Inventory

                        

Materials and supplies

   180     180          172     172         186    186                  181    181              

Other current assets

   48     43          33     26         50    36        11          35    30              
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total current assets

   1,085     1,033     46     1,239     1,211     21    877    808    44    22    11      882    854    23    12    12  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Property, plant and equipment, net

   4,932     4,932          4,638     4,638         5,141    5,141                  5,160    5,160              

Nuclear decommissioning trust funds

   1,973     1,973          2,097     2,097         2,069    2,069                  2,036    2,036              

Goodwill

   47     47          47     47         47    47                  47    47              

Mark-to-market derivatives assets

   53     53          44     44         41    41                  53    53              

Other noncurrent assets

   100     92     3     95     82     3    135    84    3    46    18      90    85    3    18    18  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total noncurrent assets

   7,105     7,097     3     6,921     6,908     3    7,433    7,382    3    46    18      7,386    7,381    3    18    18  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total assets

  $8,190    $8,130    $49    $8,160    $8,119    $24   $8,310   $8,190   $47   $68   $29     $8,268   $8,235   $26   $30   $30  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Long-term debt due within one year

  $108    $26    $77    $87    $5    $75   $265   $128   $79   $56   $45     $111   $27   $79   $46   $46  

Accounts payable

   266     266          292     292         164    164                  216    216              

Accrued expenses

   92     88     4     111     108     2    81    75    4    2    2      115    113    2    2    2  

Mark-to-market derivative liabilities

                  24     24         7    7                  5    5              

Unamortized energy contract liabilities

   10     10          22     22         12    12                  12    12              

Other current liabilities

   15     15          25     25         13    13                  13    13              
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total current liabilities

   491     405     81     561     476     77    542    399    83    58    47      472    386    81    48    48  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Long-term debt

   729     643     81     212     81     120    743    559    41    142    114      666    623    41    124    124  

Asset retirement obligations

   1,906     1,906          1,763     1,763         2,016    2,016                  1,999    1,999              

Pension obligation(a)

   9     9          9     9       

Pension obligation(c)

  9    9                  9    9              

Unamortized energy contract liabilities

   42     42          51     51         35    35                  39    39              

Other noncurrent liabilities

   65     65          127     127         76    76                  79    79              
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Noncurrent liabilities

   2,751     2,665     81     2,162     2,031     120  

Total noncurrent liabilities

  2,879    2,695    41    142    114      2,792    2,749    41    124    124  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

Total liabilities

  $3,242    $3,070    $162    $2,723    $2,507    $197   $3,421   $3,094   $124   $200   $161     $3,264   $3,135   $122   $172   $172  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

    

 

  

 

  

 

  

 

  

 

 

 

(a)

Includes CNEG retail gas pension obligation, which is presented as a net asset balance withincertain purchase accounting adjustments not pushed down to the Prepaid Pension asset line item on Generation’s balance sheet. See Note 14 — Retirement Benefits for additional details.BGE standalone entity.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

(b)

Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

(c)

Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s balance sheet. See Note 13 — Retirement Benefits for additional details.

Unconsolidated Variable Interest Entities

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

The Registrants’ unconsolidated VIEs consist of:

 

Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.

 

Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.

 

Equity investments in energy development projects,companies, distributed energy companies, and energy generating facilities for which Generation has concluded that consolidation is not required.

As of September 30, 2015March 31, 2016 and December 31, 2014,2015, Exelon and Generation had significant unconsolidated variable interests in eightnine and sixeight VIEs, respectively for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. The increaseExelon and Generation only include unconsolidated VIEs that are individually material in the numbertables below. However, Generation has several individually immaterial VIEs that in aggregate represent a total investment of unconsolidated$18 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is duelimited to the execution$18 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy purchasecompany. Generation’s total equity commitment in this arrangement was $91 million and sale agreement withwas paid incrementally over an approximate two year period (see Note 18 — Commitments and Contingencies for additional details). This arrangement did not meet the definition of a new unconsolidated VIE and was recorded as an equity method investment. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, the distributed energy company meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick out rights of the general partner. (For additional details related to the new consolidation guidance, see Note 2 — New Accounting Pronouncements.) Generation is not the primary beneficiary; therefore, the investment in a new unconsolidated VIE.continues to be recorded using the equity method.

In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of a distributed energy company. Equity will be contributed incrementally overcompany, which is an eighteen month period and will total approximately $250 million (see Note 19 — Commitments and Contingencies for additional details). Generation provides a parental guarantee of up to $275 million in support of 2015 ESA Investco, LLC’s obligation to make equity contributions to theunconsolidated VIE. The investment was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. Separate from the equity investment, Generation provided $27 million in cash to the other (10%) equity holder in the distributed energy company in exchange for a convertible promissory note. In July 2014, Generation entered into another arrangement with the same equity holder for the purchase of a 90% equity interest and 90% of the tax attributes of another distributed energy company. Generation’s total equity commitment in this arrangement was $91 million and is paid incrementally over an approximate two year period (see Note 19 — Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and is recorded as an equity method investment. Both distributed energy companies are considered related parties.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute a total of $250 million of equity incrementally from inception through December 2016 in proportion of their ownership interests, which equates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 18 — Commitments and Contingencies for additional details). Generation and the tax equity investor provide a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015 ESA Investco, LLC’s obligation to make equity contributions to the distributed energy company, which is an unconsolidated VIE. The investment in the distributed energy company was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. See additional details in the Consolidated Variable Interest Entities section above.

The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:

 

September 30, 2015

  Commercial
Agreement
VIEs
   Equity
Investment
VIEs
   Total 

March 31, 2016

  Commercial
Agreement
VIEs
   Equity
Investment
VIEs
   Total 

Total assets(a)

  $253    $131    $384    $264    $357    $621  

Total liabilities(a)

   10     66     76     15     247     262  

Exelon’s ownership interest in VIE(a)

        19     19          75     75  

Other ownership interests in VIE(a)

   243     46     289     249     35     284  

Registrants’ maximum exposure to loss:

            

Carrying amount of equity method investments

        27     27          94     94  

Contract intangible asset

   9          9     9          9  

Debt and payment guarantees

        3     3          3     3  

Net assets pledged for Zion Station decommissioning(b)

   20          20     17          17  

 

December 31, 2014

  Commercial
Agreement
VIEs
   Equity
Investment
VIEs
   Total 

December 31, 2015

  Commercial
Agreement
VIEs
   Equity
Investment
VIEs
   Total 

Total assets(a)

  $114    $91    $205    $263    $164    $427  

Total liabilities(a)

   3     49     52     22     125     147  

Exelon’s ownership interest in VIE(a)

        9     9          11     11  

Other ownership interests in VIE(a)

   111     33     144     241     28     269  

Registrants’ maximum exposure to loss:

            

Carrying amount of equity method investments

        13     13          21     21  

Contract intangible asset

   9          9     9          9  

Debt and payment guarantees

        3     3          3     3  

Net assets pledged for Zion Station decommissioning(b)

   27          27     17          17  

 

(a)

These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon corrected an error in the December 31, 2014 balances within Commercial Agreement VIEs for an overstatement of Total assets, Total liabilities and Other ownership interests in VIE of $392 million, $234 million and $158 million, respectively. The error is not considered material to any prior period.

(b)

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning include,includes gross pledged assets of $237$183 million and $319$206 million as of September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively; offset by payables to ZionSolutions LLC of $217$166 million and $292$189 million as of September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

For each of the unconsolidated VIEs, Exelon and Generation has assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

4.     Mergers, Acquisitions and Dispositions (Exelon and Generation)

Proposed Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

On April 29, 2014,March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI) signed an agreement. As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and planExelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of merger (as subsequently amendedExelon which also owns Exelon’s interests in ComEd, PECO and restated asBGE (through a special purpose subsidiary in the case of July 18, 2014,BGE). Following the Merger Agreement) to combinecompletion of the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under thePHI Merger, Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Based on the outstanding shares of PHI’s common stock as of September 30, 2015, PHI shareholders would receive $6.9 billion in total cash. In addition, in connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $180 million of a class of nonvoting, nonconvertible and nontransferable preferred securities of PHI. The preferred securities are included in Other non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any.

On September 9, 2014, Exelon and PHI filedcompleted a Notification and Report Form with DOJ under the Hart-Scott-Rodino Antitrust Improvements Actseries of 1976 (HSR Act). The HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the merger, the DOJ has not advised Exelon or PHI that it has concluded its investigation. Under the HSR Act, if the merger is not completed before December 23, 2015, Exelon and PHI are required to file again under the HSR Act and observe the required waiting period, which is 30 days from the new filing (and longer if the DOJ requests additional information), unless the DOJ terminates the waiting period earlier. Exelon and PHI intend to withdraw our pending HSR application and refile under the HSR Act on November 2, 2015. This will trigger a new 30-day waiting period. Unless a request for additional information is issued by DOJ during that waiting period, the waiting period will expire on December 2, 2015, and the parties will be free to close on or after December 2.

To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU), the Delaware Public Service Commission (DPSC), the Maryland Public Service Commission (MDPSC) and the FERC have approved the merger of PHI and Exelon. The Federal Communications Commission has also approvedinternal corporate organization restructuring transactions resulting in the transfer of certain PHI communications licenses.

On February 11, 2015, the NJBPU approved the proposed mergerPHI’s unregulated business interests to Exelon and Generation and the previously filed settlement signedtransfer of PHI, Pepco, DPL and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement providesACE to a packagespecial purpose subsidiary of benefits to ACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregate value of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million. The March 6, 2015, order by the NJBPU approving the merger required that the consummation of the merger must take place no later than November 1, 2015 unless otherwise extended by the Board. On October 15, 2015, the NJBPU extended the November 1, 2015 date to June 30, 2016.

On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the DPSC to review the proposed merger. The settlement, which was amended on April 7, 2015, was signed and filed by Exelon, PHI, Delmarva Power & Light Company (DPL), the DPSC Staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environment Control, the Delaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. As part of this settlement, Exelon and PHI proposed a package of benefits to DPL customers and the state of Delaware including the establishment of customer rate credits of $40 million for DPL customers in Delaware, $2

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)EEDC.

(Dollars in millions, except per share data, unless otherwise noted)Regulatory Matters

million of funding for energy efficiency programs for DPL low income customers, and $2 million of funding for workforce development. On June 2, 2015, the DPSC issued an order accepting the settlement and approving the merger between Exelon and PHI.

On March 17, 2015, Exelon and PHI announced that they had reached settlements with multiple parties in the Maryland proceeding to review the proposed merger after filing a Request for Adoption of Settlements with the MDPSC. The settlements were signed and filed by Exelon, PHI, Montgomery County, Prince George’s County, The Alliance for Solar Choice, the National Consumer Law Center, National Housing Trust, the Maryland Affordable Housing Coalition, the Housing Association of Nonprofit Developers, and a consortium of recreational trail advocacy organizations led by the Mid-Atlantic Off-Road Enthusiasts. On May 15, 2015, the MDPSC approved the merger after modifying a number of the conditions in the settlements, resulting in total rate credits of $66 million, funding for energy efficiency programs of $43.2 million, a Green Sustainability Fund of $14.4 million, 20 MWs of renewable generation development, ring-fencing, financial reporting conditions and increased penalties related to reliability commitments. On May 18, 2015, Exelon and PHI accepted and committed to fulfill the conditions.

On June 11, 2015, the Maryland Office of People’s Counsel (OPC), the Sierra Club, and the Chesapeake Climate Action Network filed Petitions for Judicial Review of the MDPSC’s approval of the merger with the Circuit Court for Queen Anne’s County. On June 23, 2015, Public Citizen, Inc. filed its Petition for Judicial Review with the Circuit Court for Queen Anne’s County. On July 10, 2015, Exelon and PHI filed a response in opposition to the Petitions for Review.

On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery and presentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 the Sierra Club and the Chesapeake Climate Action Network filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, Prince George’s County and Montgomery County filed responses opposing the motions to stay. The presiding judge issued an order denying the motions for stay on August 12, 2015. A hearing on the underlying Petitions for Review is scheduled for December 8, 2015.

On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of the merger, assertingconcluding that the merger as presented was not in the public’spublic interest. Exelon and PHI filed an Application for Reconsideration with the DCPSC on September 28, 2015. On October 6, 2015, various parties, including Exelon PHI, the District of Columbia Government, the Office of Peoples Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust — Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties)PHI, entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHI subsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of the Settlement Agreement and granting additional requested relief. The new package of benefits totals $78 million and includes commitments to provide relief of residential customer base rate increases of $26 million, one-time direct bill credits of $14 million, low-income energy assistance of $16 million, improved reliability, a cleaner and greener D.C. through funding energy efficiency programs and development of renewable energy, and investment in local jobs and the local economy through workforce development of $5 million. It also guarantees charitable contributions totaling $19 million over 10 years.

On October 28, 2015, the DCPSC at a public meeting agreed to reopen the approval application to allow for consideration of the Settlement Agreement. On February 26, 2016, the DCPSC rejected the Settlement Agreement and setalso voted that the merger would be deemed approved without further DCPSC action if the Settlement Agreement was modified in specific ways (Revised Settlement Agreement), and if such modifications were acceptable to Exelon, PHI, the District of Columbia Government, the Office of People’s Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties). On March 7, 2016, Exelon and PHI made a procedural schedule which would allow for completionfiling with the DCPSC requesting approval of the merger inthrough either (1) the first quarteradoption of 2016. If the DCPSC does not approve the Settlement Agreement withinas originally executed by the 150 day period after itSettling Parties, (2) the adoption of the Revised Settlement Agreement as a resolution on the merits, or (3) the adoption of a compromise position with modifications to the Revised Settlement Agreement. On March 23, 2016, the DCPSC approved the merger through the adoption of the Revised Settlement Agreement with a minor modification.

Approval of the merger across all jurisdictions was filed, eitherconditioned upon Exelon orand PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally speaking, requires allocation of merger benefits proportionally across all the jurisdictions. Exelon estimates total commitments of approximately $444 million on a net present value basis (excluding charitable contributions and renewable generation commitments) will be provided. The actual cost of commitments may terminatediffer by a material amount depending on the Settlement Agreement.result of final negotiations and application of the most favored nation provision. The following pre-tax costs were recognized, including the estimated impacts of applying the most favored nation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

The settlements reachedprovision, after the closing of the merger and commissionare included in Operating and maintenance expense in Exelon’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2016 and PHI’s successor Consolidated Statement of Operations and Comprehensive Income:

                  Successor     

Description

  Expected
Payment Period
  Pepco   DPL   ACE   PHI   Exelon 

Customer bill credit

  2016 —  2017  $65    $58    $62    $185    $185  

Energy efficiency

  2016 —  2021                       64  

Charitable contributions

  2016 —  2026   28     12     10     50     50  

Customer base rate credit

  2016 —  2019   26               26     26  

Delivery system modernization

  Q2 2016                       22  

Green sustainability fund

  Q2 2016                       14  

Workforce development

  2016 —  2020                       11  

Most favored nation

     19     32     48     99     129  

Other

     1     2          3     7  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    $139    $104    $120    $363    $508  
    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pursuant to the orders receivedapproving the merger, Exelon expects to datemake $73 million, $46 million and $49 million equity contributions to Pepco, DPL and ACE, respectively, in Delaware,the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 32 MWs of new generation in Maryland and New Jersey include a “most favored nation” provision which, generally speaking, requires allocationthe District of merger benefits proportionately across all the jurisdictions. When applying the most favored nation provision to the settlement terms and other conditions established in the merger approvals received to date, and as proposed in the Settlement Agreement filed with the DCPSC, Exelon and PHI currently estimate direct benefitsColumbia, 27MWs of $430 million or more on a net present value basis (excluding charitable contributions and renewable generation commitments) will be provided, including rate credits, funding for energy efficiency programs, sustainability funds and other required commitments. Exelon and PHI anticipate substantially all of such amounts will be charged to earnings at the time of merger close and will be paid by the end of 2017. An additional $50 million will be charged to earnings for charitable contributions, which are requiredexpected to be paid over a period of 10 years. Commitmentscompleted by 2018. These investments are expected to develop renewable generation, whichtotal approximately $130 million. These investments are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred. Upon completionincurred and recorded on Exelon’s and Generation’s financial statements. Exelon has also committed to purchase 100MW of wind energy to procure, under certain circumstances, wind RECs for the purpose of meeting Delaware’s renewable portfolio standards, and to maintain and promote energy efficiency and demand response programs in the PHI jurisdictions.

Pursuant to the various jurisdictions’ merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger the actual nature, amount, timingintegration process and financial reporting treatment for thesehave made other commitments may be materially different from the current projection.regarding hiring and relocation of positions.

Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. Exelon was also named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve all claims, which is subject to court approval. Final court approval, of the proposed settlement iswith a decision not anticipated until approximately 90 days after merger close.the second or third quarter of 2016. Exelon does not believe resolution of these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon’s results of operations.operations or cash flows.

Including 2014On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and through September 30,to set a schedule for discovery and presentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed a joint motion to stay. In July and August, Exelon, has incurred approximately $226 millionPHI, the MDPSC, Prince George’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

County and Montgomery County filed responses opposing the motions to stay. The judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of expense associated with the proposed merger. Of the total costs incurred, $110 million is primarily related to acquisition and integration costs and $116 million is for costs incurred to finance the transaction. The financing costs include a net loss of $64 million relatedappeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed a notice of appeal. Exelon believes the matters are without merit. These appeals are not expected to be resolved any earlier than the first quarter of 2017.

On March 25, 2016, Grid 2.0 filed an application for reconsideration of the DCPSC’s March 23, 2016 order approving the merger. On March 30, 2016, Exelon filed a reply to that application. The DCPSC has tolled the date to act upon the application until May 25, 2016 and, therefore, the DCPSC is expected to issue an order ruling on these motions by that date. On April 20, 2016, DC Public Power filed a motion to reconsider the DCPSC’s March 23, 2016 order, motion to intervene and motion to consider alternative settlement provisions (namely, that the DCPSC consider requiring the post-merger divestiture of forward-starting interest-rate swaps.Pepco’s DC-based assets to a not-for-profit independent grid operator). On April 27, 2016, Exelon filed a reply to these motions. The DCPSC is expected to issue an order ruling on these motions by May 20, 2016. On April 22, 2016, (1) the District of Columbia Office of People’s Counsel, (2) the District of Columbia Government, and (3) DC Sun and Public Citizen each filed separate applications for reconsideration of the DCPSC’s March 23, 2016 order. On April 29, 2016, Exelon filed a reply to these applications. The DCPSC is expected to issue an order ruling on these applications by May 23, 2016. These swaps were terminatedapplications for reconsideration generally argue that the DCPSC violated its regulations, utilized improper processes, abused its discretion, acted arbitrarily and capriciously, committed legal error and denied due process in approving the merger under terms that revised the Settlement Agreement offered by the companies and various parties. Exelon believes the matters are without merit.

Accounting for the Merger Transaction

The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid for PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:

(In millions of dollars, except per share data)  Total
Consideration
 

Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)

  $6,933  

Cash paid for PHI preferred stock(a)

   180  

Cash paid for PHI stock-based compensation equity awards(b)

   29  
  

 

 

 

Total purchase price

  $7,142  
  

 

 

 

(a)

As of December 31, 2015, the preferred stock was included in Other non-current assets on Exelon’s Consolidated Balance Sheet.

(b)

PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger. In connection with the $4.2Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded on Exelon’s and PHI’s Consolidated Balance Sheets as of March 23, 2016, at their estimated fair values as follows:

Preliminary Purchase Price Allocation

    

Current assets

  $2,107  

Property, plant and equipment

   11,071  

Regulatory assets

   5,118  

Other assets

   656  

Goodwill

   4,016  
  

 

 

 

Total assets

   22,968  
  

 

 

 

Current liabilities

   3,425  

Unamortized energy contracts

   1,550  

Regulatory liabilities

   297  

Long-term debt, including current maturities

   6,076  

Deferred income taxes

   3,441  

Pension and OPEB liability

   846  

Other liabilities

   191  
  

 

 

 

Total liabilities

   15,826  
  

 

 

 

Total purchase price

  $7,142  
  

 

 

 

On its successor financial statements, PHI has recorded beginning March 24, 2016, Membership interest equity of $7.2 billion, issuancegreater than the total $7.1 billion purchase price, reflecting the impacts of debt; refera $59 million deferred tax liability recorded only at Exelon Corporate to Note 10reflect unitary state income tax consequences of the merger.

The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was recognized as goodwill by PHI and Exelon at the acquisition date, reflecting the value associated with enhancing Exelon’s regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. For purposes of future required impairment assessments, the goodwill has been preliminarily assigned to PHI’s reportable units Pepco, DPL and ACE in the amounts of $1.7 billion, $1.2 billion and $1.1 billion, respectively. None of this goodwill is expected to be tax deductible.

Immediately following closing of the merger, $235 million of net assets included in the table above associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Of this amount, Exelon contributed $163 million of such net assets to Generation.

The fair values of PHI’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — Derivative Financial Instruments(Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Exelon’s and Note 11 — Debt and Credit AgreementsPHI’s carrying amount of goodwill for more information. The financing costs exclude costs to issue debt and equity.

During the three months ended September 30, 2015, Exelon, Generation, ComEd, PECOMarch 31, 2016 was as follows:

   PHI   Exelon(a) 

Beginning balance

  $    $2,672  

Goodwill from business combination

   4,016     4,016  
  

 

 

   

 

 

 

Ending balance

  $4,016    $6,688  
  

 

 

   

 

 

 

(a)

As of March 31, 2016, there were no changes to the carrying amount of goodwill for ComEd and Generation, see Note 11 — Intangible Assets of the Exelon 2015 Form 10-K for further information.

Through its wholly-owned rate regulated utility subsidiaries, most of PHI’s assets and BGE incurredliabilities are subject to cost-of-service rate regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. In applying the acquisition method of accounting, for regulated assets and integration costs, including financing costs,liabilities included in rate base or otherwise earning a return (primarily plant, property and equipment and regulatory assets earning a return), no fair value adjustments were recorded as historical cost is viewed as a reasonable proxy for fair value.

Fair value adjustments were applied to the historical cost bases of $21 million, $9 million, $3 million, $2 millionother assets and $2 million, respectively. Duringliabilities subject to rate regulation but not earning a return (including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also established, as the nine months ended September 30, 2015, Exelon, Generation, ComEd, PECOunderlying utility asset and BGE incurred acquisitionliability amounts are recoverable from or refundable to customers at historical cost (and not at fair value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and integration costs of $47 million, $24 million, $10 million, $4 millionliabilities, such as for electricity and $5 million, respectively.

During the three months ended September 30, 2014, Exelon, Generation, ComEd, PECOgas energy supply contracts as further described below. Regulatory assets and BGE incurred acquisitionliabilities established to offset fair value adjustments are amortized in amounts and integration costs, including financing costs, of $32 million, $3 million, $1 million, $1 million and $1 million, respectively. During the nine months ended September 30, 2014, Exelon, Generation, ComEd, PECO and BGE incurred acquisition and integration costs of $57 million, $4 million, $1 million,$1 million and $1 million, respectively.

The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statement of Operations and Comprehensive Income,over time frames consistent with the exceptionrealization or settlement of the financing costs,fair value adjustments, with no impact on reported net income. See Note 5 — Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.

Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and gas energy supply contracts of PHI’s wholly-owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of March 31, 2016. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. In certain instances, the valuations were based upon certain unobservable inputs, which are included within Interest expense.considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date. Amortizations were not significant for the period March 24, 2016 to March 31, 2016 at Exelon or PHI.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

The Merger Agreement alsovaluations performed in the first quarter of 2016 to assess the fair value of certain assets acquired and liabilities assumed are considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2016. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities assumed; however, Exelon expects to finalize these amounts by the end of 2016, if not sooner. The significant assets and liabilities for termination rightswhich preliminary valuation amounts are recognized at March 31, 2016 include the fair value of intangible assets and liabilities, uncertain tax positions, deferred income tax assets and liabilities, pension and OPEB plans, long-term debt, and unregulated property, plant and equipment. The preliminary amounts recognized are subject to revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and could potentially impact goodwill.

As mentioned, under cost-of-service rate regulation, rates charged to customers are established by a regulator to provide for both parties.recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI’s utility registrants, and therefore the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.

The current quarter impact of PHI, including its unregulated businesses, on Exelon’s Consolidated Statement of Operations and Comprehensive Income includes Operating revenues of $107 million and Net loss of $(315) million during the three months ended March 31, 2016.

For the periods ended March 31, 2016 and 2015, Exelon and PHI have entered into a Letter Agreement relatedrecognized expense to achieve the Settlement Agreement which has the practical effectPHI acquisition as follows:

   Three Months Ended
March 31,
 

Acquisition, Integration and Financing Costs(a)

  2016  2015 

Exelon

  $102   $108  

Generation

   16    7  

ComEd(b)

   (8  3  

PECO

   2    1  

BGE

   2    1  

Pepco

   27    1  

DPL

   16    1  

ACE

   13    1  

   Successor   Predecessor 

Acquisition, Integration and Financing Costs(a)

  March 24, 2016
to March 31,
2016
   January 1,
2016 to March 23,
2016
   Three Months
Ended March 31,
2015
 

PHI

  $56    $29    $8  

(a)

The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statement of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

(b)

Excludes acquisition, integration and financing costs of $9 million incurred at ComEd that have been recorded as a regulatory asset.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Pro-forma Impact of suspending their rights to terminate the Merger Agreement until November 20, 2015

The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon as if no schedulethe merger with PHI had taken place on January 1, 2015. The unaudited pro forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.

The unaudited pro forma financial information has been set bypresented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the DCPSC allowing for approvalmerger events taken place on the dates indicated, or the future consolidated results of operations of the settlement by March 4, 2016, or until March 4, 2016, if a schedule is set for approval by March 4, 2016, but approval does not occur by that date. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement is terminated due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to $180 million (the amount of purchased nonvoting preferred securities of PHI described above), through the redemption by PHI of the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock, plus reimbursement of PHIs documented out-of-pocket expenses up to a maximum of $40 million.combined company.

Merger Financing

   Three Months Ended March 31,   Year Ended
December 31,
 
         2016(a)               2015(b)         2015(c) 

Total operating revenues

  $8,556    $10,062    $33,823  

Net income attributable to common shareholders

   577     800     2,618  

Basic earnings per share

  $0.63    $0.87    $2.85  

Diluted earnings per share

   0.62     0.87     2.84  

As of September 30, 2015, through the issuance of $5.4 billion of debt (including $1.15 billion of junior subordinated notes in the form of 23 million equity units), the issuance of $1.9 billion of common stock, and cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion), Exelon has sufficient cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments. See Note 11 — Debt and Credit Agreements and Note 17 — Common Stock for further information on the debt and equity issuances. See Note 4 — Merger and Acquisitions of the Exelon 2014 Form 10-K for further information on the asset sales.

(a)

The amounts above exclude non-recurring costs directly related to the merger of $639 million and intercompany revenue of $170 million for the three months ended March 31, 2016.

(b)

The amounts above exclude non-recurring costs directly related to the merger of $116 million and intercompany revenue of $122 million for the three months ended March 31, 2015.

(c)

The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015.

Asset Divestitures (Exelon, Generation, PHI, Pepco and Generation)ACE)

At March 31, 2016, Generation had net liabilities held for sale of $5 million which were reflected within Other current assets and Other current liabilities in the Consolidated Balance Sheet. The assets held for sale at December 31, 2015 were not material. On JanuaryApril 21, 2015,2016, Generation closed oncompleted the sale of the Quail Runretired New Boston generating facility. Generation has sold generating assets for totalsite, located in the Boston, Massachusetts, resulting in a pre-tax proceedsgain of $1.8 billion (after-tax proceeds of $1.4 billion), including Quail Run and Safe Harbor, which are expectedapproximately $32 million to be used primarily to finance a portionrecorded in the second quarter. In addition, Pepco and ACE had net assets held for sale of the acquisition$4 million and related costs$1 million, respectively, which were reflected within Other current assets and expenses of PHI.

Other current liabilities in their Consolidated Balance Sheets. The assets held for sale at December 31, 2015 were not material. On August 8, 2014 Generation closed onMay 2, 2016, Pepco completed the sale of its 67% economic equity interestthe New York Avenue land parcel, located in the 417 MW Safe Harbor Water Power Corporation hydroelectric facility on the Susquehanna RiverWashington, D.C., resulting in Pennsylvania for a purchase price of approximately $615 million. Generation recorded a pre-tax gain on the sale of approximately $329$8 million within Gain on salesat Pepco to be recorded in the second quarter. Due to the fair value adjustments recorded at Exelon and PHI as part of assets on Exelon’spurchase accounting, no gain will be recorded in the Exelon and Generation’sPHI Consolidated Statements of Operations and Comprehensive Income.

5.     Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K and Note 7 — Regulatory Matters of the PHI 2015 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Energy Infrastructure Modernization ActDistribution Formula Rate (Exelon and ComEd).    Since 2011, ComEd’sOn April 13, 2016, ComEd filed its annual distribution rates are established through a performance-basedformula rate formula,with the ICC pursuant to EIMA. EIMA also provides a structure for substantial capital investmentThe filing establishes the revenue requirement used to set the ratesthat will take effect in January 2017 after the ICC’s review and approval, which is due by utilities to modernize Illinois’ electric utility infrastructure. EIMA was scheduled to sunset, ending ComEd’s performance based rate formula and investment commitment, at December 31, 2017, unless approved to continue through 2022 by the Illinois General Assembly. On April 3, 2015, the Governor signed legislation extending the EIMA sunset from 2017 to 2019.2016. The

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. As of September 30, 2015, and December 31, 2014, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $240 million and $371 million, respectively. The regulatory asset associated with distribution true-up is amortized to Operating revenues as the associated amounts are recovered through rates.

On April 15, 2015, ComEd filed its annual distribution formula rate with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2016 after the ICC’s review and approval, which is due by December 2015. The revenue requirement requested is based on 20142015 actual costs plus projected 20152016 capital additions as well as an annual reconciliation of the revenue requirement in effect in 20142015 to the actual costs incurred that year. ComEd’s 20152016 filing request includes a total decreaseincrease to the revenue requirement of $50$138 million, reflecting an increase of $92$139 million for the initial revenue requirement for 20162017 and a decrease of $142$1 million related to the annual reconciliation for 2014.2015. The revenue requirement for 20162017 provides for a weighted average debt and equity return on distribution rate base of 7.05%6.71% inclusive of an allowed ROE of 9.14%8.64%, reflecting the average rate on 30-yeartreasury notes plus 580 basis points. The annual reconciliation for 20142015 provided for a weighted average debt andequity return on distribution rate base of 7.02%6.69% inclusive of an allowed ROE of 9.09%8.59%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points.

On October 19, 2015, the ALJ issued Seetable below for ComEd’s regulatory assets associated with its proposed order indistribution formula rate. For additional information on ComEd’s current distribution formula rate proceeding, recommending a total decrease tofilings see Note 3 — Regulatory Matters of the revenue requirement of $68 million as compared to ComEd’s requested decrease of $50 million discussed above. The $18 million reduction consisted of a $8 million decrease to the initial 2016 revenue requirement and a decrease of $10 million related to the 2014 annual reconciliation. The ALJs proposed order has no independent legal effect as the ICC must vote on a final order by mid DecemberExelon 2015 which may materially vary from the findings and conclusions in the proposed order. If the ICC provides significant changes to ComEd’s filed revenue requirement request, it could have a material impact on ComEd’s current and future results of operations and cash flows.

Participating utilities are also required to file an annual update on their AMI implementation progress. On April 1, 2015, ComEd filed an annual progress report on its AMI Implementation Plan with the ICC, which allows for the installation of more than 4 million smart meters throughout ComEd’s service territory by 2018. To date, over 1.6 million smart meters have been installed in the Chicago area.Form 10-K.

Grand Prairie Gateway Transmission Line (Exelon and ComEd).On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. The costs incurred for the project prior to May 21, 2014 were immaterial. On October 22, 2014,ComEd has acquired numerous easements across the ICC issued an order approving ComEd’s Grand Prairie Gateway Project overproject route through voluntary transactions. ComEd is seeking toacquire the objection of numerous landowners and the City of Elgin. On January 15, 2015, the City of Elgin and other parties filed a Notice of Appealremaining rights either through settlement or condemnation proceedings that are currently pending in the Illinois Appellate Court. On April 8, 2015, the ICC issued a rehearing order denying the

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(Dollars in millions, except per share data, unless otherwise noted)

proposals filed by certain landowners to consider an alternate route for a three-mile segment of the transmission line. The rehearing order affirmed the route approved within the ICC’s October 22, 2014 order. On July 8, 2015, the ICC approved ComEd’s request for eminent domain to involuntarily acquire easements across 28 land parcels. On September 28, 2015, ComEd filed a petition with the ICC to acquire an additional eight parcels through eminent domain.relevant circuit courts. ComEd began construction of the line during the second quarter of 2015 with an expected in-service date expected inof the second quarter of 2017.

Pennsylvania Regulatory Matters

2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO).    On March 27, 2015, PECO filed a petition with the PAPUC requesting an increase of $190 million to its annual service revenues for electric delivery, which requested an ROE of 10.95%. On September 10, 2015, PECO and interested parties filed with the PAPUC a petition for joint settlement for an increase of $127 million in annual distribution service revenue. No overall ROE was specified in the settlement. On October 28, 2015, the ALJ issued a Recommended Decision to the PAPUC that the joint settlement be approved. A final ruling from the PAPUC is expected by December 2015, and if approved, the new electric delivery rates will take effect on January 1, 2016.

Pennsylvania Procurement Proceedings (Exelon and PECO).    On October 12, 2012, theThrough PECO’s first two PAPUC issued its Opinion and Order approving PECO’s secondapproved DSP Program, which was filed with the PAPUC in January 2012. The program, which had a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129. In the second DSP Program,Programs, PECO entered into contracts with PAPUC-approved bidders, including Generation, to procureprocured electric supply for its default electric customers through fivePAPUC approved competitive procurements. DSP I and DSP II expired on May 31, 2013 and May 31, 2015, respectively.

In addition, theThe second DSP Program included a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income Customer Assistance Program (CAP)CAP customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan with the PAPUC. By an Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, (the Court), claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On July 14, 2015, the Court issued opinions on the OCA and low-income advocacy group appeal. Specifically, the Court remanded the issue to the PAPUC with instructions that it approve a rule revision to the PECO CAP Shopping Plan that would prohibit CAP customers from entering into contracts with an EGS that would impose early cancellation/termination fees. The PAPUC appealed the Court’s decision. On April 5, 2016, the PAPUC’s request for appeal was denied. PECO does not have information at this time as to what action it may be required to take following remand to the PAPUC.

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(Dollars in millions, except per share data, unless otherwise noted)

On December 4, 2014, the PAPUC approved PECO’s third DSP Program. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. Under the program, PECO is procuring electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June 2016, the medium commercial class (101-500 kW) will move to spot market pricing. As of September 30, 2015,March 31, 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the first twothree of its four scheduled procurements. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Consolidated Statement of Operations and Comprehensive Income.

On March 12, 2015,17, 2016, PECO settled the CAP Designfiled its fourth DSP Program with the Office of Consumer Advocates (OCA) and Low Income Advocates, and filed the proposed plan with the PAPUC on March 20, 2015.PAPUC. The program design

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(Dollarshas a 24-month term from June 1, 2017 through May 31, 2019, and complies with electric generation procurement guidelines set forth in millions, except per share data, unless otherwise noted)

changes the rate structure of PECO’s CAP to make the bills more affordable to customers enrolledAct 129. A PAPUC ruling is expected in the assistance program. The CAP discounts continue to be recovered through PECO’s universal service fund cost. On July 8, 2015, the CAP Design was approved by the PAPUC. PECO plans to implement the program changes in Octoberlate 2016.

Smart Meter and Smart Grid Investments (Exelon and PECO).    In April 2010, pursuant to Act 129 and the follow-on Implementation Order of 2009, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP). PECO is currently in the second phase of the SMPIP, under which PECO will deploy substantially all remaining smart meters, for a total of 1.7 million smart meters, on an accelerated basis by the end of 2015. In total, PECO currently expects to spend up to $591 million, excluding the cost of the original meters, on its smart meter infrastructure and approximately $155 million on smart grid investments through final deployment of which $200 million was primarily funded by SGIG. As of September 30, 2015, PECO has spent $579 million and $155 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received.

For further information on the SGIG and Smart Meter and Smart Grid program,Pennsylvania procurement proceedings, see Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K.

Pennsylvania Act 11 of 2012Energy Efficiency Programs (Exelon and PECO).    In February 2012, Act 11 was signed into law, which seeks to clarify the PAPUC’s authority to approve alternative ratemaking mechanisms, allowing for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC’s implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure.

On May 7,June 19, 2015, the PAPUC approvedissued its Phase III EE&C implementation order that provides energy consumption reduction requirements for the third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021. The order tentatively established PECO’s modified natural gas LTIIP. In accordance withfive-year cumulative consumption reduction target at 2,080,553 MWh.

Pursuant to the approved LTIIP, PECO plans to spend $534 million through 2022 to further accelerate the replacement of existing gas mains and to relocate meters from indoors to outside in accordance with recent PAPUC rulemaking. In addition, on March 20, 2015,Phase III implementation order, PECO filed a petitionits five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for approval of its gas DSIC mechanism for recovery of gas LTIIP expenditures. On September 11, 2015, the period June 1, 2016 through May 31, 2021. The PAPUC entered its Opinion and Order approvingapproved PECO’s petition for a gas DSIC.

OnEE&C Phase III Plan on March 27, 2015, PECO filed a petition with the PAPUC for approval of its proposed electric DSIC and LTIIP. In accordance with the LTIIP (System 2020 plan), PECO plans to spend $275 million over the next five years to modernize and storm-harden its electric distribution system, making it more weather resistant and less vulnerable to damage. The DSIC will allow PECO the opportunity to recover the costs,17, 2016, subject to certain criteria, incurred to repair, improve or replaceclarification of a few minor issues. PECO refiled its electric distribution property between rate cases. On October 22,Phase III Plan, with all requested clarifications, on March 31, 2016.

For further information on energy efficiency programs, see Note 3 — Regulatory Matters of the Exelon 2015 the PAPUC entered its Opinion and Order approving PECO’s proposed petition for its electric LTIIP and DSIC.Form 10-K.

Maryland Regulatory Matters

2016 Maryland Electric Distribution Rate Case (Exelon, PHI and Pepco).    On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its annual service revenues for electric delivery, based on a requested ROE of 10.6%. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. In addition to the proposed $127 million rate increase, Pepco is proposing to continue its Grid Resiliency Charge initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. In connection with the Grid Resiliency Charge, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict how much of the requested increase the MDPSC will approve or if it will approve Pepco’s Grid Resiliency Charge proposal.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE).    On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, respectively.MDPSC. In addition to these requested rate increases, BGE’s application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the ERI initiative) in response to a MDPSC order through a surcharge separate from base rates.

On December 13, 2013, the MDPSC issued an order in BGE’s 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. Rates became effective for services rendered on or

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

afterOn December 13, 2013. The2013, the MDPSC also authorizedissued an order authorizing BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. OnAs of March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed2016, BGE has received approval of its updated surcharge filings three times for completionrates to be effective in 2014, as part of the ERI initiative. The ERI initiative surcharge became effective June 1, 2014. On November 3, 2014, BGE filed a surcharge update including a true-up of cost estimates included in the 2014 surcharge, along with its work plan2015 and cost estimates for 2015, to be included in the 2015 surcharge. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2014 annual report, 2015 work plan and the 2015 surcharge.2016.

In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE’s 2013 electric and gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC’s approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. BGE cannot predictOn October 26, 2015, the outcome of this appeal. IfCircuit Court for Baltimore City issued an order affirming the MDPSC decision. However, on November 23, 2015, the residential consumer advocate’sadvocate filed an appeal of the Circuit Court’s decision with the Maryland Court of Special Appeals. On March 7, 2016, the consumer advocate withdrew its appeal and no further action is successful, BGE could recover ERI expenditures through other regulatory mechanisms.expected.

Smart Meter and Smart Grid Investments (Exelon and BGE).    In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciationand amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of September 30, 2015March 31, 2016 and December 31, 2014,2015, BGE recorded a regulatory asset of $179$212 million and $128$196 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE’s 2014 electric and gas distribution rate case, the cost of the retired non-AMI meters will be amortized over 10 years.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE).    In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to recover promptly reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC’s approvalAs part of the eligible infrastructure replacement projects along with2015 electric and gas distribution rate case filed on November 6, 2015, BGE is seeking recovery of its smart grid initiative costs. Of BGE’s requested $197 million, $141 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs on a corresponding surcharge, BGE could begin charging gas customerspresent value basis by a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes capsratio of 2.3 to 1.0, on the monthly surcharges to residential and non-residential customers, and would require an annual true-upa nominal basis. For further information, see Note 3 — Regulatory Matters of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap,Exelon 2015 Form 10-K.

MDPSC New Generation Contract Requirement (Exelon, Generation, BGE, is required to file a gas rate case every five years under this legislation.PHI, Pepco and DPL).    On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014,April 12, 2012, the MDPSC issued an order that requires BGE, Pepco and DPL (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 MW beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs will recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MDPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MDPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. In November 2013 both the winning bidder and the MDPSC appealed the Federal district court decision conditionally approvingto the first five yearsU.S. Court of BGE’s plan and surcharge.Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On MarchNovember 26, 2014, both the winning bidder and the MDPSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge updatepetitioned the U.S. Supreme Court to be effective January 1, 2015 including a true-up of cost estimates included in the 2014 surcharge, along with its 2015 project list and projected capital estimates of $78 million to be included in the 2015 surcharge calculation. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2015 project list and the proposed surcharge for 2015, which included the true-up of the 2014 charge. As of September 30, 2015, BGE recorded a regulatory liability of $1 million, representing the difference between the surcharge revenues and program costs.consider

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(Dollars in millions, except per share data, unless otherwise noted)

 

In February 2014, the residential consumer advocate in Maryland filedhearing an appeal withof the Baltimore CityFourth Circuit decision. On October 19, 2015, the U.S. Supreme Court agreed to review the decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit’s ruling upholding the Federal district court’s decision.

The decision of the Maryland Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement plan. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE’s infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential consumer advocate noticed its appealwas appealed to the Maryland Court of Special Appeals from the judgment enteredand was stayed pending decision by the Baltimore City CircuitU.S. Supreme Court. DuringThe U.S. Supreme Court decision will likely moot the third quarter of 2015,state court action pending in the residential consumer advocate, MDPSC and BGE filed briefs. The Court of Special Appeals has set oral argument in this matter for November 3, 2015. BGE cannot predict the outcome of this appeal. However, if the consumer advocates appeal is successful, BGE could seek recovery of infrastructure replacement costs through other regulatory mechanisms.Maryland.

New YorkDelaware Regulatory Matters

Ginna Nuclear Power Plant Reliability Support Services AgreementGas Cost Rates.    (Exelon, PHI and Generation).    DPL)Ginna Nuclear Power Plant’s (Ginna) prior period fixed-price PPA contractDPL makes an annual GCR filing with Rochester Gas & Electric Company (RG&E) expired in June 2014.the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In light of the expiration of the agreement, Ginna advised the New York Public Service Commission (NYPSC) and ISO-NY that in absence of a reliability need, Ginna management would make a recommendation, subject to approval by the CENG board, that Ginna be retired as soon as practicable. A formal study conducted by the ISO-NY and RG&E concluded that the Ginna nuclear plant needs to remain in operation to maintain the reliability of the transmission gridAugust 2015, DPL made its 2015 GCR filing. The rates proposed in the Rochester region through 2018 when planned transmission system upgrades are expected to be completed. In November 2014,2015 GCR filing would result in response to a petition filed by Ginna,GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the NYPSC directed Ginna and RG&E to negotiate a Reliability Support Services Agreement (RSSA). On February 13, 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continued operation of Ginna for reliability purposes were made with the NYPSC and with FERC for their approval. Although the RSSA contract is still subject to regulatory approvals, on April 1, 2015, Ginna began delivering power and capacity into ISO-NY consistent with the provisions of the proposed RSSA contract. In the event that Ginna continues to operate beyond the RSSA term, Ginna would be required to make a specified refund payment to RG&E. The FERCDPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval. On March 22, 2016, the DPSC approved the Gas Cost Rate as filed.

2013 Electric Distribution Base Rates (Exelon, PHI and DPL).    In March 2013, and as amended on September 20, 2013, DPL filed for an electric distribution base rate increase with the DPSC, ultimately requesting an annual increase of $42 million.

In August 2014, the DPSC issued a final order in DPL’s 2013 electric distribution rate case for an annual increase of $15 million and an ROE of 9.70%. Rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the Settlement Agreement related to the Merger, the parties agreed to suspend the appeal and, upon consummation of the Merger, to the withdrawal of the appeal and the cross-appeal with prejudice. In accordance with the settlement, on April 14, 2015, directing Ginna13, 2016, the parties filed a Stipulation of Dismissal with the court to make a compliance filing to ensure thatdismiss the RSSA doesappeal and the cross-appeal. The court has not allow Ginna to receive revenues above its full cost-of-serviceyet acted on this filing.

District of Columbia Regulatory Matters

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and rejecting any extensionPepco).    On May 3, 2014, the Council of the RSSA beyond its initial term, rather requiring any extensionDistrict of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the DC PLUG initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be subjectowned and maintained by Pepco.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a surcharge on the electric bills of Pepco District of Columbia customers that Pepco will remit to the rules currently being developedDistrict of Columbia; and (iii) the remaining costs up to $125 million are to be covered by ISO-NY. The FERC order also set the RSSA for hearing and settlement procedures. In response to the FERC’s April 14, 2015 order, on May 14, 2015, Ginna submitted a compliance filing to FERC containing proposed revisions to the RSSA addressing FERC’s requirements and maintaining the April 1, 2015 proposed effective date. On July 13, 2015, FERC accepted Ginna’s compliance filing effective April 1, 2015. The FERC accepted Ginna’s proposal for market revenue sharing subject to a cap effective April 1, 2015, and rejected requests for rehearing by parties on a number of matters related to jurisdiction, the reliability need, RSSA term, and possible price suppression. In late August, Ginna reached a settlement in principle with interested parties modifying certain terms and conditions in the originally negotiated agreement. The proposed RSSA under the settlement preserves the valueexisting capital projects program of the contract originally negotiated with RG&E, but shortensDistrict of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the term to March 31, 2017 and requires RG&E to complete a new transmission reliability study to determine if an interim reliability solution is required beyond March 31, 2017. The reliability study is expected to be completed by the end of 2015. If there continues to be a reliability need beyond March 31, 2017, RG&E has the right until June 30, 2016 to select Ginna as an ongoing reliability solution. If Ginna is not selected for continued reliability service and does not plan to retire shortly after RSSA expiration, Ginna is required to file a notice with the NYPSC no later than September 30, 2016. The settlement was filed at the NYPSC and at FERC on October 21, 2015 and remains subject to review and approval by both agencies, which do not expect to be completed until the first quarter of 2016.

Until final regulatory approvals are received, Generation will recognize revenue based on market prices for energy and capacity delivered by Ginna into ISO-NY. Upon receiving regulatory approvals, under the RSSA

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contract terms,cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

On June 17, 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. On August 1, 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance (the DDOT surcharge).

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. On March 17, 2016, the District of Columbia Court of Appeals denied the original petitioning party’s motion for rehearing.

Separately, in June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely delay implementation of the DC PLUG initiative.

New Jersey Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and ACE).    On March 22, 2016, ACE filed an application with the NJBPU requesting an increase of $84 million to its annual service revenues for electricdelivery, based on a requested ROE of 10.6%. In addition to the request for base rate relief, ACE has also included a request that the NJBPU approve ACE’s five-year grid resiliency initiative known as “PowerAhead.” As proposed, PowerAhead includes $176 million of capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system’s ability to withstand major storm events. A decision is expected in the first half of 2017. ACE cannot predict how much of the requested increase the NJBPU will approve or if it will approve ACE’s PowerAhead initiative.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE).    On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the NUGs and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollected accounts.

The net impact of adjusting the charges as proposed is an overall annual rate increase of $9 million (revised to $19 million in April 2016, based upon an update for actuals through March 2016), including New Jersey sales and use tax. The matter is pending at the NJBPU. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Standard Offer Capacity Agreements (Exelon, PHI and ACE).    On April 28, 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. On October 11, 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit on September 11, 2014.

On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit decision, discussed above under “MDPSC New Generation would recordContract Requirement,” holding that the MDPSC’s required contracts are illegal and unenforceable. On April 25, 2016, the U.S. Supreme Court ruled not to review the Third Circuit decision. This denial leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an adjustmentevent of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to recognizethe October 2013 Federal district court decision.

New York Regulatory Matters

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation).    In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possibleretirement of Ginna, the New York Public Service Commission (NYPSC) directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.

On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC accepted the compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA. Because all regulatory approvals for the RSSA have now been received, Generation will begin recognizing revenue based on the final approved pricing contained in the contract asRSSA. Generation will also recognize a one-time revenue adjustment in April 2016 of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date. Whiledate through March 31, 2016. A 49.99% portion of the one-time adjustment will be removed from Generation’s results as a result of the non-controlling interest in CENG.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The RSSA approved by the regulatory authorities has a term expiring on March 31, 2017, subject to possible extension in the event that RG&E needs additional time to complete transmission upgrades to address reliability concerns. In March 2016, RG&E notified Ginna that RG&E expects to complete the transmission upgrades prior to the RSSA expiration in March 2017 and will not need Ginna as an ongoing reliability solution after that date.

If Ginna does not plan to retire shortly after the expiration of the RSSA, Ginna is expectedrequired to receive regulatory approvals and, therefore, permitfile a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the RSSA, if Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments up to a maximum of $20 million to RG&E related to capital expenditures.

The approved RSSA requires Ginna to continue operating through the RSSA term, there is still aterm. There remains an increased risk that, for economic reasons, including adjustments to the revenue Ginna would be entitled to under the RSSA, Ginna could be retired before the end of its operating license period.period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. In absence of such an agreement and in the event the plant iswere to be retired before the current license term ends in 2029, Exelon’s and Generation’s results of operations could be adversely affected by increased depreciation rates, impairment charges, severance costs, andthe accelerated future decommissioning costs, severance costs, increased depreciation rates, and impairment charges, among other items. However, it is not expected that suchSee Note 7-Implications of Potential Early Plant Retirements for further information regarding the impacts would be materialof a decision to Exelon’searly retire one or Generation’s results of operations.more nuclear plants.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and BGE)ACE).    ComEd’s and BGE’s transmission rates are each established based on a FERC-approved formula. ComEd and BGE are required to file an annual update toThe following tables provide information about the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of September 30, 2015 and December 31, 2014, ComEd had recorded a net regulatory asset or liabilities associated with the transmission formula rate of $26 million and $21 million, respectively. Asthe indicated registrants as of September 30, 2015March 31, 2016 and December 31, 2014, BGE recorded a net regulatory asset associated with the transmission formula rate of $5 million and $1 million, respectively.2015. The regulatory asset associated with the transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.

               Successor             

As of March 31, 2016

  Exelon   ComEd   BGE   PHI   Pepco   DPL   ACE 

Regulatory Assets(a)

  $60    $31    $17    $12    $4    $7    $1  
               Predecessor             

As of December 31, 2015

  Exelon   ComEd   BGE   PHI   Pepco   DPL   ACE 

Regulatory Assets(a)(b)

  $43    $31    $12    $14    $5    $7    $2  

(a)

The regulatory assets represent a component of the costs included within the energy and transmission regulatory programs. Refer to Regulatory Assets and Liabilities table for additional information.

(b)

The Exelon consolidated amounts do not include the regulatory assets of PHI, Pepco, DPL, and ACE at December 31, 2015.

On April 15, 2015 (and revised on May 19),13, 2016, ComEd filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that tookwill take effect in June 2015,2016, subject to review by the FERC and other parties, which is due by fourth quarter 2015.2016. ComEd’s 20152016 annual update includes a total increase to the revenue requirement of $86$94 million, reflecting an increase of $68$90 million for the initial revenue requirement and an increase of $18$4 million related to the annual reconciliation. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.61%8.47%, inclusive of an allowed ROE of 11.50%, a decrease from the 8.62%8.61% average debt and equity return previously authorized.

InOn April 2015,27, 2016, BGE filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that tookwill take effect in June 2015,2016, subject to review by the FERC and other parties, which is due by October 2015.third quarter 2016. BGE’s 2015 2016

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

annual update includes a total increase to the revenue requirement of $10$15 million, reflecting an increase of $13$12 million for the initial revenue requirement and a decrease of $3 million related to the annual reconciliation. This increase excludes the $13 million increase in revenue requirement associated with dedicated facilities charges. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.46%8.09%, inclusive of an allowed ROE of 11.30%,10.50% a decrease from the 8.53%8.46% average debt and equity return previously authorized.

For additional information regarding ComEd and BGE’s transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

FERC Transmission Complaint (Exelon, BGE, PHI, Pepco, DPL and BGE)ACE).    OnIn February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE, Pepco, DPL and PHI companiesACE relating to their respective transmission formula rates. BGE’s formula rate includesincluded a 10.8% base rate of ROE and a 50 basis point incentive for participating in PJM (the latter(and certain additional incentive base points on certain projects). Pepco’s, DPL’s and ACE’s formula rates included, for facilities placed into service after January 1, 2006, a base ROE of which is conditioned upon crediting the first11.3%, and for facilities placed into service prior to January 1, 2006, a base ROE of 10.8% and a 50 basis points of anypoint incentive ROE adders).for participating in PJM. The parties seeksought a reduction in the base ROEreturn on equity to 8.7% and changes to the formula

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests andanswers. Under FERC rules, theany revenues subject to refund are limited to a fifteen month period and the earliestdate from which the base ROE could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint.

On August 21, 2014, FERC issued an order in the BGE and PHI companies’ proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013. BGE,

On February 23, 2016, FERC approved the PHI companies andsettlement filed by the parties beganon November 6, 2015, covering the ROE issues raised in the complaints. The settlement discussions underprovides for a 10% base ROE, effective March 8, 2016, which will be augmented by the guidancePJM incentive adder of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the Settlement Judge informed FERC50 basis points, and the Chief Judge that the parties had reached an impasserefunds to customers of BGE, Pepco, DPL and determined that aACE of $13.7 million, $14.2 million, $11.9 million and $9.5 million, respectively. The settlement was not possible. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at the hearings and directing that an initial decision be issued by November 25, 2015.

On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regardingalso prohibits any settling party from filing to change the base ROE of the transmission business seeking a reduction from 10.8%or any incentives prior to 8.8%.June 1, 2018. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants’ requested refund effective date of December 8, 2014. On February 20, 2015, the Chief Judge issued an order consolidating the two complaint proceedings and established an Initial Decision issuance deadline of February 29, 2016. On March 2, 2015, the Presiding Administrative Law Judge issued an order establishing a procedural schedule for the consolidated proceedings that provides for the hearing to commence on October 20, 2015. On September 14, 2015, the complainants and respondents filed a joint motion to suspend the hearing schedule because they have reached a settlement in principle to resolve the ROE issue. On September 15, 2015, the Chief Administrative Law Judge issued an order granting the motion, and setting October 15, 2015 as the date for the moving parties to either file a settlement or file a status report detailing the timetable for filing a settlement which was subsequently extended to October 30, 2015.

On October 30, 2015,request for rehearing has expired without any such requests having been filed. Accordingly, the parties filed a status report stating their intent to either file a settlement or file another status report duringorder is not eligible for appeal and the fourth quarter of 2015.

Based on the current status of the complaint filings, BGE believes itmatter is probable that BGE’s base ROE rate will be adjusted, and that a refund to customers of transmission revenue for the two maximum fifteen month periods will be required. BGE has established a reserve, which management believes is adequate for what it considers to be the most likely outcome. The estimated annual ongoing reduction in revenues if FERC approves the ROEs as originally requested by the parties in their initial filings is approximately $11 million. If FERC were to order a reduction of BGE’s base ROE to 8.7% and 8.8% as sought in the first and second complaints, respectively (while retaining the 50 basis points of any incentives that were credited to the base ROE for certain new transmission investment), the result would be a refund to customers of approximately $13 million and $14 million, for the first and second fifteen month refund windows, respectively, for a total refund to customers of approximately $27 million.considered closed.

PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE).    PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. The hearing only concerns new facilities approved by the PJM Board prior to February 1, 2013. As of September 30, 2015, settlement discussions are continuing.

Because a new cost allocation had been adopted for projects approved by the PJM Board on or after February 1, 2013, this latest remand only involves the cost allocation for facilities 500 kV and above approved prior to that date. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd’s results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO’s 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO’s results of operations, cash flows or financial position. To the extent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE’s results of operations, cash flows or financial position.

Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE).    On May 23, 2014, the D.C. Circuit Court issued an opinion vacating the FERC Order No. 745 (D.C. Circuit Decision). Order No. 745 established uniform compensation levels for demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective.

In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained that demand response is part of the retail market and FERC is restricted from regulating retail markets. After the D.C. Circuit denied rehearing in September 2014, the FERC sought to appeal the decision to the U.S. Supreme Court in January 2015. The U.S. Supreme Court agreed to consider the appeal. Oral argument was held at the U.S. Supreme Court on October 14, 2015. A decision is expected to be issued by the U.S. Supreme Court before the end of the term ending on June 30, 2016.

In addition, contemporaneously with the D.C. Circuit Court’s decision on May 23, 2014, FirstEnergy filed a complaint at the FERC asking the FERC to direct PJM to remove all PJM Tariff provisions that allow or require PJM to compensate demand response providers as a form of supply in the PJM capacity market effective May 23, 2014. FirstEnergy also asked the FERC to declare the results of PJM’s May 2014 Base Residual Auction for the 2017/2018 Delivery Year, void and illegal to the extent that demand response resources cleared that auction. On November 14, 2014, the New England Power Generators Association, Inc. (NEPGA) filed a similar complaint at the FERC asking the FERC to disqualify demand response from the upcoming capacity auction in New England and to revise the New England tariff to remove demand response from participation in the capacity market. The FERC’s response to the FirstEnergy complaint and the NEPGA complaint and its response to address the D.C. Circuit Court’s decision in all markets could preclude demand response resources from receiving any future capacity market revenues and also subject such resources to refund obligations depending on how the U.S. Supreme Court resolves the matter. In addition, there is uncertainty as to how the FERC might treat already settled capacity market auctions as well as future auctions, both for demand response resources and generation resources, again depending on the U.S. Supreme Court resolution. Due to these uncertainties, the Registrants are

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

unable to predict the outcome of these proceedings, and the final outcome is not expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material to Exelon, Generation, ComEd, PECO and BGE’s results of operations and cash flows.

New England Capacity Market Results (Exelon and Generation).    Each year, ISO New England, Inc. (ISO-NE) files the results of its annual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction. Consistent with this requirement, on February 27, 2015, ISO-NE filed the results of its ninth capacity auction (covering the June 1, 2018 through May 31, 2019 delivery period). On June 18, 2015, the FERC accepted the results of the ninth capacity auction. On July 20, 2015, a union representing utility workers sought rehearing of that decision. While it is unlikely that the FERC would alter its decision on rehearing, Exelon and Generation cannot predict with certainty what future actions the FERC may take concerning the results of the auction. Adverse action by the FERC could ultimately be material to Exelon’s and Generation’s expected revenues from the auction.

On February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 31, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE filed the information on July 17, 2014, and the ISO-NE’s filings became effective by operation of law pursuant to a notice issued by the secretary of FERC on September 16, 2014. Several parties sought rehearing of the secretary’s notice which was effectively denied in October 2014 and have since appealed the matter to the D.C. Circuit Court. On April 7, 2015 the D.C. Circuit Court issued an order referring the matter to a merits panel where issues raised by parties challenging the FERC decision will be heard as well as FERC’s Motion to Dismiss the challenges. It is not clear whether the court will decide ultimately on the merits of the case or whether it will dismiss the case as FERC urges based on the fact that there is no action by the FERC to be considered. Nonetheless, while any change in the auction results is thought to be unlikely, Exelon and Generation cannot predict with certainty what further action the court may take concerning the results of that auction, but any court action could be material to Exelon’s and Generation’s expected revenues from the capacity auction.

License Renewals (Exelon and Generation).    On August 29, 2012, and August 30, 2012, Generation submitted a hydroelectric license applicationsapplication to FERC for a 46-year licenseslicense for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Project (Muddy Run), respectively.

. Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Generation filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed.issues. MDE indicated that it believed it did not have sufficient information to process Generation’s application. As a result, on December 5, 2014, Generation withdrew its pending application for a water quality certification. FERC policy requires that an applicant resubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, on March 3, 2015, Generation refiled its application for a water quality certification. In addition, Generation has entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Generation has agreed to contribute up to $3.5 million to fund the additional study. In addition, because of the ongoing sediment and nutrient monitoring study, and because states must act upon water quality certification applications within a year of submission, Exelon agreed with Maryland to coordinate the withdrawal and refiling of the application in accordance with FERC policy that requires an applicant to resubmit its request for a water quality certification within 90 days of the date of withdrawal.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

On August 7, 2015, US Fish and Wildlife Service (USFWS)of the US Department of the Interior (Interior) submitted its modified fishway prescription to FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for an administrative hearing and proposed an alternative prescription to challenge USFWS’sDOI’s preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all issues between Exelon and Interior relating to fish passage at Conowingo. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. Resolution of thesethe remaining issues relating to Conowingo may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

On June 3, 2014, and subsequently modified December 9, 2014, the PA DEP issued its water quality certificate for Muddy Run, which is a necessary step in the FERC licensing process and included certain commitments made by Generation. On March 2, 2015, Generation and USFWS submitted to FERC an executed settlement agreement resolving all outstanding issues related to Muddy Run. The financial impact associated with these commitments is estimated to be in the range of $25 million to $35 million, and will include both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects.

The FERC licenseslicense for Muddy Run and Conowingo expired on August 31, 2014 and September 1, 2014 respectively.2014. Under the Federal Power Act, FERC is required to issue an annual licenseslicense for the facilitiesa facility until the new licenses arelicense is issued. On September 10, 2014, FERC issued an annual licenseslicense for Conowingo, and Muddy Run, effective as of the expiration of the previous licenses.license. If FERC does not issue a new licenseslicense prior to the expiration of an annual licenses,license, the annual licenseslicense will renew automatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Muddy Run and Conowingo.

The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of September 30, 2015, $43March 31, 2016, $25 million of direct costs associated with the Conowingo licensing effortseffort have been capitalized.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and BGE)ACE)

Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and BGEACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

The following tables provide information aboutAs a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of Exelon, ComEd, PECO and BGE as of September 30, 2015 and December 31, 2014. For additional information onfair valuing the specific regulatoryacquired assets and liabilities referassumed which are subject to Note 3 — Regulatory Mattersregulatory recovery. In total, Exelon and PHI recorded a net $2.5 billion regulatory asset reflecting adjustments recorded as a result of the Exelon 2014 Form 10-K.acquisition method of accounting.

September 30, 2015

  Exelon   ComEd   PECO   BGE 

Regulatory assets

        

Pension and other postretirement benefits

  $3,138    $    $    $  

Deferred income taxes

   1,589     66     1,446     77  

AMI programs

   373     130     64     179  

Under-recovered distribution service costs(a)

   240     240            

Debt costs

   50     48     2     8  

Fair value of BGE long-term debt

   170                 

Severance

   10               10  

Asset retirement obligations

   106     66     22     18  

MGP remediation costs(g)

   289     256     32     1  

Under-recovered uncollectible accounts

   54     54            

Renewable energy

   243     243            

Energy and transmission programs(b)(c)

   67     33          34  

Deferred storm costs(g)

   2               2  

Electric generation-related regulatory asset(g)

   23               23  

Rate stabilization deferral

   101               101  

Energy efficiency and demand response programs

   271               271  

Merger integration costs

   6               6  

Conservation voltage reduction

   1               1  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

September 30, 2015

  Exelon   ComEd   PECO   BGE 

Under-recovered revenue decoupling(f)

   7               7  

Other

   39     9     23     4  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total regulatory assets

   6,779     1,145     1,589     742  
  

 

 

   

 

 

   

 

 

   

 

 

 

Less: current portion

   779     232     32     257  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total noncurrent regulatory assets

  $6,000    $913    $1,557    $485  
  

 

 

   

 

 

   

 

 

   

 

 

 

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of March 31, 2016 and December 31, 2015. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 — Regulatory Matters of the PHI 2015 Form 10-K.

 

September 30, 2015

  Exelon   ComEd   PECO   BGE 

Regulatory liabilities

        

Other postretirement benefits

  $65    $    $    $  

Nuclear decommissioning

   2,538     2,150     388       

Removal costs

   1,545     1,342          203  

Energy efficiency and demand response programs(d)

   46     44     2       

DLC Program Costs

   9          9       

Energy efficiency phase II

   38          38       

Electric distribution tax repairs

   97          97       

Gas distribution tax repairs

   30          30       

Energy and transmission programs(b)(c)(e)

   134     46     70     18  

Over-recovered electric universal service fund costs

   3          3       

Over-recovered revenue decoupling(f)

   27               27  

Other

   13     3     3     7  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total regulatory liabilities

   4,545     3,585     640     255  
  

 

 

   

 

 

   

 

 

   

 

 

 

Less: current portion

   365     144     104     69  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total noncurrent regulatory liabilities

  $4,180    $3,441    $536    $186  
  

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2014

  Exelon   ComEd   PECO   BGE 
         Successor       

March 31, 2016

 Exelon ComEd PECO BGE PHI Pepco DPL ACE 

Regulatory assets

                

Pension and other postretirement benefits

  $3,256    $    $    $  

Pension and other postretirement benefits(a)

 $4,261   $   $   $   $   $   $   $  

Deferred income taxes

   1,542     64     1,400     78    1,861    65    1,499    80    217    139    35    43  

AMI programs

   296     91     77     128  

Under-recovered distribution service costs(a)

   371     371            

Debt costs

   57     53     4     9  

Fair value of BGE long-term debt

   190                 

AMI programs(r)

  687    149    60    212    266    181    85      

Under-recovered distribution service costs(b)

  198    198                          

Debt costs(c)

  132    45    1    8    86    19    9    7  

Fair value of long-term debt(d)

  896                741              

Fair value of PHI’s unamortized energy contracts(e)

  1,535                1,535              

Severance

   12               12    8            8                  

Asset retirement obligations

   116     74     26     16    113    71    22    19    1    1          

MGP remediation costs

   257     219     37     1    276    246    29    1                  

Under-recovered uncollectible accounts

   67     67              60    60                          

Renewable energy

   207     207              265    265                          

Energy and transmission programs(b)(c)

   48     33          15  

Energy and transmission programs(f)(g)(m)(n)(o)

  118    56        38    24    5    6    13  

Deferred storm costs

   3               3    47            2    45    19    6    20  

Electric generation-related regulatory asset

   30               30    18            18                  

Rate stabilization deferral

   160               160    77            67    10    9    1      

Energy efficiency and demand response programs

   248               248    651        1    264    386    277    108    1  

Merger integration costs

   8               8    5            5                  

Conservation voltage reduction

   2               2    3            3                  

Under recovered electric revenue decoupling(f)

   7               7  

Under-recovered revenue decoupling(h)

  36            36                  

COPCO acquisition adjustment

  12                12        12      

Recoverable workers compensation and long-term disability

  31                31    31          

Vacation accrual

  43        17        26        15    11  

Securitized stranded costs

  185                185            185  

CAP arrearage

  8        8                      

Removal costs

  397                397    103    73    222  

AEC(i)

  7                7              

Other

   46     22     14     7    61    9    10    4    34    12    12    12  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total regulatory assets

   6,923     1,201     1,558     724    11,991    1,164    1,647    765    4,003    796    362    514  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Less: current portion

   847     349     29     214    1,584    239    42    266    801    133    67    95  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total noncurrent regulatory assets

  $6,076    $852    $1,529    $510  

Total non-current regulatory assets

 $10,407   $925   $1,605   $499   $3,202   $663   $295   $419  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

��

  

 

  

 

  

 

  

 

  

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

December 31, 2014

  Exelon   ComEd   PECO   BGE 
         Successor       

March 31, 2016

 Exelon ComEd PECO BGE PHI Pepco DPL ACE 

Regulatory liabilities

                

Other postretirement benefits

  $88    $    $    $   $93   $   $   $   $   $   $   $  

Nuclear decommissioning

   2,879     2,389     490         2,599    2,182    417                      

Removal costs

   1,566     1,343          223    1,669    1,334        187    148    21    127      

Energy efficiency and demand response programs(d)

   27     25     2       

DLC Program Costs

   10          10       

Energy efficiency phase II

   32          32       

Deferred rent(j)

  42       42              

Energy efficiency and demand response programs

  122    78    43        1            1  

DLC program costs

  9        9                      

Electric distribution tax repairs

   102          102         89        89                      

Gas distribution tax repairs

   49          49         25        25                      

Energy and transmission programs(b)(c)(e)

   84     19     58     7  

Over-recovered electric universal service fund costs

   2          2       

Revenue subject to refund

   3     3            

Over-recovered revenue decoupling(f)

   12               12  

Energy and transmission programs(f)(g)(k)(l)(p)(q)

  187    43    69    15    60    25    25    10  

Other

   6     1     2     2    55    2    3    10    41    9    14    16  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total regulatory liabilities

   4,860     3,780     747     244    4,890    3,639    655    212    292    55    166    27  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Less: current portion

   310     125     90     44    512    150    134    61    106    26    57    22  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total noncurrent regulatory liabilities

  $4,550    $3,655    $657    $200  

Total non-current regulatory liabilities

 $4,378   $3,489   $521   $151   $186   $29   $109   $5  
  

 

   

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

              Predecessor          

December 31, 2015

 Exelon  ComEd  PECO  BGE  PHI  Pepco  DPL  ACE 

Regulatory assets

        

Pension and other postretirement benefits

 $3,156   $   $   $   $910   $   $   $  

Deferred income taxes

  1,616    64    1,473    79    214    137    36    41  

AMI programs(r)

  399    140    63    196    267    180    87      

Under-recovered distribution service costs(b)

  189    189                 

Debt costs

  47    46    1    8    36    19    10    7  

Fair value of long-term debt(d)

  162                              

Severance

  9            9                  

Asset retirement obligations

  108    67    22    19    1    1          

MGP remediation costs

  286    255    30    1                  

Under-recovered uncollectible accounts

  52    52                          

Renewable energy

  247    247                          

Energy and transmission programs(f)(g)(k)(m)(n)(o)

  84    43    1    40    33    9    11    13  

Deferred storm costs

  2            2    43    19    6    18  

Electric generation-related regulatory asset

  20            20                  

Rate stabilization deferral

  87            87    14    10    4      

Energy efficiency and demand response programs

  279        1    278    401    289    111    1  

Merger integration costs

  6         6                  

Conservation voltage reduction

  3            3                  

Under-recovered revenue decoupling(h)

  30            30                  

COPCO acquisition adjustment

                          13      

Workers compensation and long-term disability costs

                  31    31          

Vacation accrual

  6        6        23        14    9  

Securitized stranded costs

                  202            202  

CAP arrearage

  7        7                      

Removal costs

                  369    92    69    208  

Other

  29    10    13    3    38    14    10    13  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total regulatory assets

  6,824    1,113    1,617    781    2,582    801    371    512  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Less: current portion

  759    218    34    267    305    140    72    98  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total non-current regulatory assets

 $6,065   $895   $1,583   $514   $2,277   $661   $299   $414  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

              Predecessor          

December 31, 2015

 Exelon  ComEd  PECO  BGE  PHI  Pepco  DPL  ACE 

Regulatory liabilities

        

Other postretirement benefits

 $94   $   $   $   $   $   $   $  

Nuclear decommissioning

  2,577    2,172    405                      

Removal costs

  1,527    1,332        195    150    21    129      

Energy efficiency and demand response programs

  92    52    40        1            1  

DLC program costs

  9        9                      

Electric distribution tax repairs

  95        95                      

Gas distribution tax repairs

  28        28                      

Energy and transmission programs(f)(g)(k)(l)(p)(q)

  131    53    60    18    27    16    19    8  

Over-recovered revenue decoupling(h)

  1            1                  

Other

  16    5    2    8    35    7    12    16  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total regulatory liabilities

  4,570    3,614    639    222    213    44    160    25  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Less: current portion

  369    155    112    38    66    15    49    18  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total non-current regulatory liabilities

 $4,201   $3,459   $527   $184   $147   $29   $111   $7  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

As of September 30, 2015,March 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $1,125 million established at the date of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.

(b)

As of March 31, 2016, ComEd’s regulatory asset of $240$198 million was comprised of $184$156 million for the applicable2014 — 2016 annual reconciliations and $56$42 million related to significant one-time events including $43$31 million of deferred storm costs, and $13$9 million of Constellation merger and integration related costs and $2 million of smart meter related costs. As of December 31, 2014,2015, ComEd’s regulatory asset of $371$189 million was comprised of $286$142 million for the applicable2014 and 2015 annual reconciliations and $85$47 million related to significant one-time events, including $66$36 million of deferred storm costs and $19$11 million of Constellation merger and integration related costs. See Note 4 — Mergers,Merger, Acquisitions, and Dispositions of the Exelon 20142015 Form 10-K for further information.

(b)(c)

Includes at Exelon and PHI the regulatory asset recorded at Exelon and PHI for debt costs that are recoverable through the ratemaking process at Pepco, DPL, and ACE which were eliminated at Exelon and PHI as part of acquisition accounting.

(d)

Includes the unamortized regulatory assets recorded for the difference between carrying value and fair value of long-term debt of BGE as of the Constellation merger date and at Exelon and PHI for the difference between carrying value and fair value of long-term debt of Pepco, DPL and ACE as of the PHI Merger date.

(e)

Represents the regulatory asset recorded at Exelon and PHI offsetting the fair value adjustments related to Pepco’s, DPL’s and ACE’s electricity and gas energy supply contracts recorded at PHI as of the PHI Merger date. Pepco, DPL and ACE are allowed full recovery of the costs of these supply contracts through their respective rate making processes.

(f)

As of September 30, 2015,March 31, 2016, ComEd’s regulatory asset of $33$56 million included $26$18 million related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC approved formulate rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of September 30, 2015,March 31, 2016, ComEd’s regulatory liability of $46$43 million included $24$17 million related to over-recovered energy costs for hourly customers and $22$26 million associated with revenues received for renewable energy requirements. As of December 31, 2014,2015, ComEd’s regulatory asset of $33$43 million included $4$5 million related to under-recovered energy costs, for non-hourly customers, $22$31 million associated with transmission costs recoverable through its FERC approved formulate rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2014,2015, ComEd’s regulatory liability of $19$53 million included $3$29 million related to over-recovered energy costs for hourly customers and $16$24 million associated with revenues received for renewable energy requirements.

(c)(g)

As of September 30, 2015,March 31, 2016, BGE’s regulatory asset of $34$38 million included $5 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $29$33 million related to under-recovered electric energy costs. As of September 30, 2015,March 31, 2016, BGE’s regulatory liability of $18$15 million related to $9$2 million of over-recovered natural gas supplytransmission costs and $14 million of over-recovered energynatural gas costs, offset by $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE’s regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE’s regulatory liability of $7 million related to over-recovered natural gas supply costs.

(d)

ComEd recovers the costs of its ICC-approved Energy Efficiency and Demand Response plan through a rider. Effective with a change to its rider in August 2015, ComEd will recover or refund any under or over-recoveries through the end of the Plan’s fiscal year on May 31 over a twelve-month period beginning on June 1 of the following calendar year. Previously, ComEd’s recovery or refund of under or over-recoveries through the end of the Plan’s fiscal year on May 31 was over a nine-month period beginning on September 1 of the same calendar year.

(e)

As of September 30, 2015, PECO’s regulatory liability of $70 million included $33 million related to the DSP program, $31 million related to the over-recovered natural gas costs under the PGC and $6 million related to over-recovered electric transmission costs. As of December 31, 2014, PECO’s regulatory liability of $58 million included $39 million related to the DSP program, $16 million related to the over-recovered natural gas costs under the PGC and $3 million related to the over-recovered electric transmission costs.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

(f)

recovered upon FERC approval. As of December 31, 2015, BGE’s regulatory asset of $40 million included $12 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $28 million related to under-recovered electric energy costs. As of December 31, 2015, BGE’s regulatory liability of $18 million related to $14 million of over-recovered transmission costs and $5 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be recovered upon FERC approval.

(h)

Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30,March 31, 2016, BGE had a regulatory asset of $31 million related to under-recovered electric revenue decoupling and a regulatory asset of $5 million related to under-recovered natural gas revenue decoupling. As of December 31, 2015, BGE had a regulatory asset of $7$30 million related to under-recovered electric revenue decoupling and a regulatory liability of $27 million related to over-recovered natural gas revenue decoupling. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12$1 million related to over-recovered natural gas revenue decoupling.

(g)(i)

In accordanceRepresents the regulatory asset recorded at Exelon and PHI for the difference between the carrying value and fair value of alternative energy credits at Pepco, DPL and ACE recorded at Exelon and PHI that are recoverable through the rate making process.

(j)

Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease that is recoverable through the ratemaking process at Pepco, DPL and ACE which was eliminated at PHI as part of acquisition accounting.

(k)

As of March 31, 2016, PECO’s regulatory liability of $69 million included $36 million related to the DSP program, $26 million related to the over-recovered natural gas costs under the PGC, $3 million related to over-recovered electric transmission costs and $4 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2015, PECO’s regulatory asset of $1 million related to under-recovered non-bypassable transmission service charges. As of December 31, 2015, PECO’s regulatory liability of $60 million included $35 million related to the DSP program, $22 million related to the over-recovered natural gas costs under the PGC and $3 million related to the over-recovered electric transmission costs.

(l)

As of March 31, 2016, DPL’s regulatory liability of $25 million included $6 million related to over-recovered natural gas costs under the GCR mechanism, $7 million of over-recovered electric energy costs, and $12 million of over-recovered transmission costs. As of December 31, 2015, DPL’s regulatory liability of $19 million included $4 million related to the over-recovered natural gas costs under the GCR mechanism, $4 million of over-recovered electric energy costs, and $11 million of over-recovered transmission costs.

(m)

As of March 31, 2016, Pepco’s regulatory asset of $5 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $1 million of under-recovered electric energy costs. As of December 31, 2015, Pepco’s regulatory asset of $9 million included $5 million of transmission costs recoverable through its FERC approved formula rate and $4 million of recoverable abandonment costs.

(n)

As of March 31, 2016, DPL’s regulatory asset of $6 million related to transmission costs recoverable through its FERC approved formula rate. As of December 31, 2015, DPL’s regulatory asset of $11 million included $7 million of transmission costs recoverable through its FERC approved formula rate, $3 million of recoverable abandonment costs, and $1 million of under-recovered electric energy costs.

(o)

As of March 31, 2016, ACE’s regulatory asset of $13 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $12 million of under-recovered electric energy costs. As of December 31, 2015, ACE’s regulatory asset of $13 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs.

(p)

As of March 31, 2016, Pepco’s regulatory liability of $25 million included $15 million of over-recovered transmission costs and $10 million of over-recovered electric energy costs. As of December 31, 2015, Pepco’s regulatory liability of $16 million included $14 million of over-recovered transmission costs and $2 million of over-recovered electric energy costs.

(q)

As of March 31, 2016, ACE’s regulatory liability of $10 million related to over-recovered transmission costs. As of December 31, 2015, ACE’s regulatory liability of $8 million related to over-recovered transmission costs.

(r)

Represents AMI costs associated with the MDPSCinstallation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved 2014 electric and natural gas distribution rate case orders,by the recovery periodsNJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets were revised, effective in January 2015.assets.

Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and BGE)ACE)

ComEd, PECO, BGE, Pepco, DPL and BGEACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and Maryland, respectively,New Jersey, to purchase certain receivables from

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

retail electric and natural gas suppliers that participate in the utilities’ consolidated billing. ComEd, BGE, Pepco and BGEDPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO isand ACE are required to purchase receivables at face value and are permitted to recover uncollectible accounts expense from customers through its distribution rates. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and BGEACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and BGE’sACE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrantsthose companies as of September 30, 2015March 31, 2016 and December 31, 2014.2015.

 

As of September 30, 2015

  Exelon  ComEd  PECO  BGE 

Purchased receivables(a)

  $296   $137   $90   $69  

Allowance for uncollectible accounts(b)

   (40  (22  (8  (10
  

 

 

  

 

 

  

 

 

  

 

 

 

Purchased receivables, net

  $256   $115   $82   $59  
  

 

 

  

 

 

  

 

 

  

 

 

 

As of December 31, 2014

  Exelon  ComEd  PECO  BGE 

Purchased receivables(a)

  $290   $139   $76   $75  

Allowance for uncollectible accounts(b)

   (42  (21  (8  (13
  

 

 

  

 

 

  

 

 

  

 

 

 

Purchased receivables, net

  $248   $118   $68   $62  
  

 

 

  

 

 

  

 

 

  

 

 

 
               Successor           

As of March 31, 2016

  Exelon  ComEd  PECO  BGE  PHI  Pepco  DPL   ACE 

Purchased receivables(c)

  $343   $96   $75   $66   $106   $77   $11    $18  

Allowance for uncollectible accounts(a)

   (38  (16  (8  (8  (6  (4       (2
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

 

Purchased receivables, net

  $305   $80   $67   $58   $100   $73   $11    $16  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

 
               Predecessor           

As of December 31, 2015

  Exelon  ComEd  PECO  BGE  PHI  Pepco  DPL   ACE 

Purchased receivables(b)

  $229   $103   $67   $59   $100   $70   $11    $19  

Allowance for uncollectible accounts(a)

   (31  (16  (7  (8  (6  (4       (2
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

 

Purchased receivables, net

  $198   $87   $60   $51   $94   $66   $11    $17  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

   

 

 

 

 

(a)

For ComEd, BGE, Pepco, DPL and ACE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.

(b)

PECO’s gas POR program became effective on January 1, 2012 and includesincluded a 1% discount on purchased receivables in order to recover the implementation costs of the program. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.

(b)(c)

For ComEdPepco’s electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and BGE, reflectsPepco’s electric POR program in the incremental allowance for uncollectible accounts recorded, which is in additionDistrict of Columbia included a discount on purchased receivables ranging from 0% to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.6% depending on customer class.

6.     Investment in Constellation Energy Nuclear Group, LLCImpairment of Long-Lived Assets (Exelon and Generation)

Long-Lived Assets (Exelon and Generation)

During the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its upstream subsidiary CEU Holdings, LLC (as described in Note 10 — Debt and Credit Agreements) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values at March 31, 2016. As a result, a pre-tax impairment charge of the Constellation merger, Generation owns a 50.01% interest$119 million was recorded in CENG, a nuclear generation business. Generation has historically had various agreements with CENG to purchase powerMarch 2016 within Operating and to provide certain services. For further information regarding these agreements, see Note 25 — Related Party Transactions of the Exelon 2014 Form 10-K.

As a result of the consolidation of CENG on April 1, 2014, there are several additional transactions includedmaintenance expense in Exelon’s and Generation’s consolidated financial statements between CENGConsolidated Statements of Operations and Exelon’s affiliates that are considered related party transactions to Generation. AsComprehensive Income. After reflecting the impairment charges, Generation has $63 million of Upstream assets remaining on its Consolidated Balance Sheets at March 31, 2016. Further declines in commodity prices or further described in Note 25 — Related Party Transactionsdevelopments with Generation’s intended use or disposition of the Exelon 2014 Form 10-K, EDF and Generation had a PPA with CENG under which they purchased 15% and 85%, respectively,assets could potentially result in future impairments of the nuclear output owned by CENG thatUpstream assets.

The fair value analysis was not sold to third partiesprimarily based on the income approach using significant unobservable inputs (Level 3) including commodity prices and production volumes, projected capital and maintenance expenditures and discount rates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

under pre-existing PPAs through December 31, 2014. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG not subject to other contractual agreements. Beginning April 1, 2014, CENG’s sales to Generation have been eliminated in consolidation. For the three and nine months ended September 30, 2015, Generation had sales to EDF of $108 million and $395 million, respectively. See Note 3 — Variable Interest Entities for additional information regarding other transactions between CENG and EDF included within Exelon’s and Generation’s consolidated financial statements and for additional information about the Registrant’s VIEs.

Accounting for the Consolidation of CENG

Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in earnings of unconsolidated affiliates related to its investment in CENG and $17 million of revenues from CENG. The book value of Generation’s investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million.

The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014 resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s Consolidated Balance Sheets.

Generation and EDFI also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDFI has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return and the value of Generation’s rights to other distributions. The beginning of the exercise period will be accelerated if Exelon’s affiliates cease to own a majority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months.

Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interest on the Consolidated Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution considers Generation’s Preferred Distribution Rights and allocates net income based on each owner’s rights to CENG’s net assets. For the three and nine months ended September 30, 2015, Generation reduced by $5 million and $13 million, respectively, the amount of Net income attributable to noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $110 million and $416 million and CENG’s net income (loss), prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $(75) million and $18 million during the three and nine months ended September 30, 2015, respectively.

7.    Impairment of Long-Lived Assets (Exelon and Generation)

Long-Lived Assets (Exelon and Generation)

Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of each year, Generation updates

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

the long-term fundamental energy prices, which includes a thorough evaluation of key assumptions including gas prices, load growth, environmental policy, plant retirements and renewable growth.

In 2015, the year over year change in fundamentals did not indicate any impairments. In 2014, the year over year change in fundamentals suggested that the carrying value of certain merchant wind assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014. As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 million was recorded during the second quarter of 2014 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.

During the third quarter of 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon’s and Generation’s Consolidated Balance Sheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated fair value less costs to sell. At September 30, 2014, in connection with the approved asset sales agreements, a $50 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Like-Kind Exchange Transaction (Exelon)

Prior to the PECO/Unicom Merger in OctoberIn June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into a like-kind exchange transactiontransactions pursuant to which approximately $1.6 billion wasUII invested in coal-fired generating station leases located in(Headleases) with the Municipal Electric Authority of Georgia and Texas with two separate entities unrelated to Exelon.(MEAG). The generating stations were leased back to such entitiesMEAG as part of the transaction. See Note 12 — Income Taxes for further information. The leases fortransactions (Leases).

On March 31, 2016, UII and MEAG finalized an agreement to terminate the generating stations located in Texas were terminated in 2014. For financial accounting purposes,MEAG Headleases, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The leaseMEAG Leases, and other related agreements provide the lessees with fixed purchase options at the endprior to their expiration dates. As a result of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the power itself or require the lessees to arrange for a third-party to bid on a service contract for a period following the lease term. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In the fourth quarter of 2000, under the terms of the lease agreements,termination, UII received a prepaymentan early termination payment of $1.2 billion for all rent, which reduced$360 million from MEAG and wrote-off the $356 million net investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases.

Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments under the income approach,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

which uses a discounted cash flow analysis, which takes into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates,MEAG Headleases and the estimated remaining useful livesLeases. The transaction resulted in a pre-tax gain of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained$4 million which is reflected in the lease agreements.

Based on the annual reviews performed in the second quarters of 2015 and 2014, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other than temporary declines given increases in estimated long-term operating and maintenance costs in the 2015 annual review and reduced long-term energy and capacity price expectations in the 2014 annual review. As a result, Exelon recorded $24 million pre-tax impairment charges in each of the second quarters of 2015 and 2014 for these stations. These impairment charges were recorded in Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the Consolidated Statements of Operations and Comprehensive Income. See Note 11 — Income respectively. Changes in the assumptions described above could potentially result in future impairments of Exelon’s direct financing lease investments, which could be material.Taxes for additional information.

At September 30, 2015 and December 31, 2014, the components of the net investment in long-term leases were as follows:

   September 30,
2015
   December 31,
2014
 

Estimated residual value of leased assets

  $639    $685  

Less: unearned income

   291     324  
  

 

 

   

 

 

 

Net investment in long-term leases

  $348    $361  
  

 

 

   

 

 

 

8.7.     Implications of Potential Early Plant Retirements (Exelon and Generation)

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions in New York and Illinois such as the recently proposed Zero Emission Standard element of the Next Generation Energy Plan (NGEP) or Low Carbon Portfolio Standard (LCPS) legislation in Illinois and Clean Energy Standard (CES) in New York, the impact of final rules from the U.S. EPA requiring reduction of carbon and other emissions and the efforts of the states to implement those final rules, and the outcome of the Ginna RSSA hearing and settlement procedures and the resulting contractual terms and conditions. On September 10, 2015, after considering the results of the recent PJM capacity auctions, Exelon and Generation decided to defer for one year any decisions about the future operations of its Quad Cities and Byron nuclear plants and will offer both plants in the 2019/2020 auction in May 2016. As a result of clearing the other PJM capacity auction in September 2015 for the 2017/2018 transitional capacity auction, Exelon and Generation will continue to operate its Quad Cities nuclear power plant through at least May 2018. The Byron plant is already obligated to operate through May 2019. rules.

In addition, on October 29, 2015, Exelon and Generation decideddeferred retirement decisions on Clinton and Quad Cities until 2016 in order to defer any decision aboutparticipate in the future operations2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity auction to be held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois. In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjusted rate of itsreturn to shareholders. The results of the 2019-2020 PJM capacity auction will be available on May 24, 2016.

On May 6, 2016 Exelon and Generation announced intentions to shut down the Clinton nuclear plant for one yearon June 1, 2017 and plan to bid theQuad Cities nuclear plant into the MISO capacity auction for the 2016/2017 planning year in March 2016. MISO’s announcement on October 27, 2015 acknowledging the need for market design changes in southernJune 1, 2018 if Illinois was a key factor in Exelon’s and Generation’s decision to defer for an additional year, among other factors such as positive results from the Illinois Power Agency’s capacity procurement fordoes not pass adequate legislation by May 31, 2016 and if Quad Cities does not clear the long-term impact of the EPA’s Clean Power Plan. The Clinton plant is currently obligated to operate through May 2016.2019-2020 PJM capacity auction. Exelon and Generation previously committed to cease operation of the Oyster Creek nuclear plant by the end of 2019. ExelonThe approved RSSA requires Ginna to continue operating through the RSSA term expiring in March 2017. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. Refer to Note 5 — Regulatory Matters for additional discussion on the Ginna RSSA.

In response to a decision to early retire one or more nuclear plants, certain changes in accounting treatment would be triggered and Generation have not made any decisions regarding potential nuclear plant closuresExelon’s and Generation’s results of operations and cash flows could be materially affected by, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other sites at this time.nuclear units and cancellation of in-flight capital projects, contract termination fees, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.), accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioning trust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

As a result of a decision to early retire one or more other nuclear plants, certain changes in accounting treatment would be triggered and Exelon’s and Generation’s results of operations and cash flows could be materially affected by a number of items including, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of decommissioning costs. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown. While there are a number of Generation’s nuclear plants that are at risk of early retirement, theThe following table provides the balance sheet amounts as of September 30, 2015March 31, 2016 for significant assets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement due to their current economic valuations and other factors:factors.

 

(in millions)  Quad Cities Clinton Ginna Total   Quad Cities Clinton Ginna Total 

Asset Balances

          

Materials and supplies inventory

  $49   $56   $30   $135    $47   $58   $30   $135  

Nuclear fuel inventory, net

   186    122    65    373     213    95    54    362  

Completed plant, net

   1,027    582    111    1,720     1,014    574    127    1,715  

Construction work in progress

   29    8    23    60     28    11    11    50  

Liability Balances

          

Asset retirement obligation

   (696  (396  (637  (1,729   (706  (407  (651  (1,764

NRC License Renewal Term

   2032    2046(a)   2029      2032    2046(a)   2029   

 

(a)

Assumes Clinton seeks and receives a 20-year operating license renewal extension.

In the event a decision is made to early retire one or more nuclear plants, theThe precise timing of thean early retirement date, and resulting financial statement impact, is uncertain and wouldmay be influencedaffected by a number of factors, such asincluding the results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations and just prior to its next scheduled nuclear refueling outage date in that year.

9.8.    Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Fair Value of Financial Liabilities Recorded at the Carrying Amount

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) and preferred stock as of September 30, 2015March 31, 2016 and December 31, 2014:2015:

Exelon

 

  September 30, 2015   March 31, 2016 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $678    $3    $675    $    $678    $3,643    $3    $3,640    $    $3,643  

Long-term debt (including amounts due within one year)(a)

   25,438     1,004     24,181     1,335     26,520     31,372     1,132     29,577     2,135     32,844  

Long-term debt to financing trusts(b)

   648               663     663     641               670     670  

SNF obligation

   1,021          820          820     1,022          817          817  

   December 31, 2015 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $536    $3    $533    $    $536  

Long-term debt (including amounts due within one year)(a)

   25,145     931     23,644     1,349     25,924  

Long-term debt to financing trusts(b)

   641               673     673  

SNF obligation

   1,021          818          818  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   December 31, 2014 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $463    $3    $448    $12    $463  

Long-term debt (including amounts due within one year)

   21,164     1,208     20,417     1,311     22,936  

Long-term debt to financing trusts

   648               648     648  

SNF obligation

   1,021          833          833  

Generation

 

  September 30, 2015   March 31, 2016 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $21    $    $21    $    $21    $1,529    $    $1,529    $    $1,529  

Long-term debt (including amounts due within one year)(a)

   8,996          7,978     1,335     9,313     9,052          7,539     1,549     9,088  

SNF obligation

   1,021          820          820     1,022          817          817  

 

  December 31, 2014   December 31, 2015 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $36    $    $24    $12    $36    $29    $    $29    $    $29  

Long-term debt (including amounts due within one year)(a)

   8,266          7,511     1,311     8,822     8,959          7,767     1,349     9,116  

SNF obligation

   1,021          833          833     1,021          818          818  

ComEd

 

  September 30, 2015   March 31, 2016 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $604    $    $604    $    $604    $643    $    $643    $    $643  

Long-term debt (including amounts due within one year)(a)

   6,100          6,731          6,731     6,510          7,357          7,357  

Long-term debt to financing trust

   206               206     206  

Long-term debt to financing trusts(b)

   205               207     207  

 

  December 31, 2014   December 31, 2015 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $304    $    $304    $    $304    $294    $    $294    $    $294  

Long-term debt (including amounts due within one year)(a)

   5,958          6,788          6,788     6,509          7,069          7,069  

Long-term debt to financing trust

   206               213     213  

Long-term debt to financing trusts(b)

   205               213     213  

PECO

 

  September 30, 2015   March 31, 2016 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Long-term debt (including amounts due within one year)(a)

  $2,246    $    $2,472    $    $2,472    $2,581    $    $2,900    $    $2,900  

Long-term debt to financing trusts

   184               196     196     184               196     196  

   December 31, 2015 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Long-term debt (including amounts due within one year)(a)

  $2,580    $    $2,786    $    $2,786  

Long-term debt to financing trusts

   184               195     195  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   December 31, 2014 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Long-term debt (including amounts due within one year)

  $2,246    $    $2,537    $    $2,537  

Long-term debt to financing trusts

   184               199     199  

BGE

 

  September 30, 2015   March 31, 2016 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $53    $3    $50    $    $53    $153    $3    $150    $    $153  

Long-term debt (including amounts due within one year)(a)

   1,905          2,118          2,118     1,859          2,119          2,119  

Long-term debt to financing trusts(b)

   258               261     261     252               267     267  

 

  December 31, 2014   December 31, 2015 
  Carrying
Amount
   Fair Value   Carrying
Amount
   Fair Value 
  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $123    $3    $120    $    $123    $213    $3    $210    $    $213  

Long-term debt (including amounts due within one year)(a)

   1,942          2,178          2,178     1,858          2,044          2,044  

Long-term debt to financing trusts(b)

   258               236     236     252               264     264  

PHI

   March 31, 2016 
   Carrying
Amount
   Fair Value 
Successor    Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $1,317    $    $1,317    $    $1,317  

Long-term debt (including amounts due within one year)

   6,132          5,540     586     6,126  

   December 31, 2015 
   Carrying
Amount
   Fair Value 
Predecessor    Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $958    $    $958    $    $958  

Long-term debt (including amounts due within one year)(a)

   5,279          5,231     586     5,817  

Preferred stock

   183               183     183  

Pepco

   March 31, 2016 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Long-term debt (including amounts due within one year)(a)

  $2,352    $    $2,876    $    $2,876  

   December 31, 2015 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $64    $    $64    $    $64  

Long-term debt (including amounts due within one year)(a)

   2,351          2,673          2,673  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

DPL

   March 31, 2016 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $75    $    $75    $    $75  

Long-term debt (including amounts due within one year)(a)

   1,265          1,238     103     1,341  

   December 31, 2015 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $105    $    $105    $    $105  

Long-term debt (including amounts due within one year)(a)

   1,265          1,185     103     1,288  

ACE

   March 31, 2016 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Long-term debt (including amounts due within one year)(a)

  $1,191    $    $1,081    $288    $1,369  

   December 31, 2015 
   Carrying
Amount
   Fair Value 
     Level 1   Level 2   Level 3   Total 

Short-term liabilities

  $5    $    $5    $    $5  

Long-term debt (including amounts due within one year)(a)

   1,201          1,044     280     1,324  

(a)

Includes unamortized debt issuance costs of $179 million, $72 million, $37 million, $14 million, $9 million, $31 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of March 31, 2016. Includes unamortized debt issuance costs of $180 million, $70 million, $38 million, $15 million, $9 million, $49 million, $31 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2015.

(b)

Includes unamortized debt issuance costs of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of March 31, 2016 and December 31, 2015.

Short-Term Liabilities.Liabilities.    The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1), and short-term borrowings (Level 2) and third party financing (Level 3). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.

Long-Term Debt.Debt.    The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Due to low trading volume of private

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

placement debt, qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3. The fair value of Exelon’s equity units (Level 1) are valued based on publicly traded securities issued by Exelon.

The fair value of Generation’s and PHI’s non-government-backed fixed rate project financingnonrecourse debt including nuclear fuel procurement contracts, (Level 3) is based on market and quoted prices for its own and other project financingnonrecourse debt with similar risk profiles. Given the low trading volume in the project financingnonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate project financing debt resets on a monthly or quarterly basis and

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

the carrying value approximates fair value (Level 2). When trading data is available on variable rate project financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also hashave tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.

SNF Obligation.Obligation.    The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025.

Long-Term Debt to Financing Trusts.Trusts.    Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

Preferred Stock.    The fair value of these securities is determined based on the carrying value of the shares per the Subscription Agreement between PHI and Exelon. See Note 16 — Mezzanine Equity for further details.

Recurring Fair Value Measurements

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

 

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

 

Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts. ThereAdditionally, there were no significant transfers between Level 1 and Level 2 during the ninethree months ended September 30, 2015March 31, 2016 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.

For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Generation and Exelon

(Dollars in millions, exceptIn accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share data, unless otherwise noted)

Exelonas a practical expedient are no longer classified within the fair value hierarchy and Generationare included under “Not subject to leveling” in the table below. See Note 2 — New Accounting Pronouncements for additional information.

The following tables present assets and liabilities measured and recorded at fair value on Exelon’s and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2015March 31, 2016 and December 31, 2014:2015:

 

  Generation Exelon  Generation Exelon 

As of September 30, 2015

  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

As of March 31, 2016

 Level 1 Level 2 Level 3 Not
subject to
leveling
 Total Level 1 Level 2 Level 3 Not
subject to
leveling
 Total 

Assets

                   

Cash equivalents(a)

  $225   $   $   $225   $6,545   $   $   $6,545   $130   $   $   $   $130   $721   $   $   $   $721  

Nuclear decommissioning trust fund investments

         

Cash equivalents

   301    67        368    301    67        368  

Equity

         

Domestic

   2,274    1,829        4,103    2,274    1,829        4,103  

Foreign

   598            598    598            598  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Equity funds subtotal

   2,872    1,829        4,701    2,872    1,829        4,701  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

NDT fund investments

          

Cash equivalents(a)

  266    11            277    266    11            277  

Equities

  3,273    21    1    1,875    5,170    3,273    21    1    1,875    5,170  

Fixed income

                   

Corporate debt

       1,831    245    2,076        1,831    245    2,076        1,868    243        2,111        1,868    243        2,111  

U.S. Treasury and agencies

   1,142            1,142    1,142            1,142    1,402    13            1,415    1,402    13            1,415  

Foreign governments

       77        77        77        77        45            45        45            45  

State and municipal debt

       407        407        407        407        285            285        285            285  

Other

       468        468        468        468  

Other(b)

      64        376    440        64        376    440  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Fixed income subtotal

   1,142    2,783    245    4,170    1,142    2,783    245    4,170    1,402    2,275    243    376    4,296    1,402    2,275    243    376    4,296  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Middle market lending

           423    423            423    423            440        440            440        440  

Private equity

           116    116            116    116                130    130                130    130  

Real estate

           30    30            30    30                40    40                40    40  

Other

       329        329        329        329                190    190                190    190  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Nuclear decommissioning trust fund investments subtotal(b)

   4,315    5,008    814    10,137    4,315    5,008    814    10,137  

NDT fund investments subtotal(c)

  4,941    2,307    684    2,611    10,543    4,941    2,307    684    2,611    10,543  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Pledged assets for Zion Station decommissioning

                   

Cash equivalents

       11        11        11        11    35                35    35                35  

Equities

   5    1        6    5    1        6    1    7            8    1    7            8  

Fixed income

                   

U.S. Treasury and agencies

   5    2        7    5    2        7    3    2            5    3    2            5  

Corporate debt

       57        57        57        57        25            25        25            25  

State and municipal debt

       10        10        10        10  

Other

       1        1        1        1  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Fixed income subtotal

   5    70        75    5    70        75    3    27            30    3    27            30  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Middle market lending

           144    144            144    144            25    85    110            25    85    110  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Pledged assets for Zion Station decommissioning subtotal(c)

   10    82    144    236    10    82    144    236  

Pledged assets for Zion Station decommissioning subtotal(d)

  39    34    25    85    183    39    34    25    85    183  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Rabbi trust investments in mutual funds(d)(e)

   16            16    46            46  

Commodity derivative assets

         

Economic hedges

   1,625    2,561    2,144    6,330    1,625    2,561    2,144    6,330  

Proprietary trading

   85    140    38    263    85    140    38    263  

Effect of netting and allocation of collateral(f)

   (1,865  (2,037  (835  (4,737  (1,865  (2,037  (835  (4,737
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Commodity derivative assets subtotal

   (155  664    1,347    1,856    (155  664    1,347    1,856  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Interest rate and foreign currency derivative assets

         

Derivatives designated as hedging instruments

                       37        37  

Economic hedges

       21        21        21        21  

Proprietary trading

   14    3        17    14    3        17  

Effect of netting and allocation of collateral

   (8  (6      (14  (8  (6      (14
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Interest rate and foreign currency derivative assets subtotal

   6    18        24    6    55        61  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   Generation  Exelon 

As of September 30, 2015

  Level 1  Level 2  Level 3  Total  Level 1  Level 2  Level 3  Total 

Other investments

           32    32            32    32  

Total assets

   4,417    5,772    2,337    12,526    10,767    5,809    2,337    18,913  
         

Liabilities

         

Commodity derivative liabilities

         

Economic hedges

   (2,120  (2,478  (1,209  (5,807  (2,120  (2,478  (1,452  (6,050

Proprietary trading

   (79  (140  (44  (263  (79  (140  (44  (263

Effect of netting and allocation of collateral(f)

   2,218    2,472    1,080    5,770    2,218    2,472    1,080    5,770  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Commodity derivative liabilities subtotal

   19    (146  (173  (300  19    (146  (416  (543
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative liabilities

         

Derivatives designated as hedging instruments

       (21      (21      (21      (21

Economic hedges

       (6      (6      (6      (6

Proprietary trading

   (15          (15  (15          (15

Effect of netting and allocation of collateral

   15    6        21    15    6        21  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative liabilities subtotal

       (21      (21      (21      (21
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Deferred compensation obligation

       (29      (29      (95      (95
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total liabilities

   19    (196  (173  (350  19    (262  (416  (659
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total net assets

  $4,436   $5,576   $2,164   $12,176   $10,786   $5,547   $1,921   $18,254  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

   Generation   Exelon 

As of December 31, 2014

  Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total 

Assets

                

Cash equivalents(a)

  $405    $    $    $405    $1,119    $    $    $1,119  

Nuclear decommissioning trust fund investments

                

Cash equivalents

   208     37          245     208     37          245  

Equity

                

Domestic

   2,423     2,207          4,630     2,423     2,207          4,630  

Foreign

   612               612     612               612  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity funds subtotal

   3,035     2,207          5,242     3,035     2,207          5,242  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fixed income

                

Corporate debt

        2,023     239     2,262          2,023     239     2,262  

U.S. Treasury and agencies

   996               996     996               996  

Foreign governments

        95          95          95          95  

State and municipal debt

        438          438          438          438  

Other

        511          511          511          511  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fixed income subtotal

   996     3,067     239     4,302     996     3,067     239     4,302  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Middle market lending

             366     366               366     366  

Private equity

             83     83               83     83  

Real estate

             3     3               3     3  

Other

        301          301          301          301  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Nuclear decommissioning trust fund investments subtotal(b)

   4,239     5,612     691     10,542     4,239     5,612     691     10,542  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pledged assets for Zion Station

decommissioning

                

Cash equivalents

        15          15          15          15  

Equities

   6     1          7     6     1          7  

Fixed income

                

U.S. Treasury and agencies

   5     3          8     5     3          8  

Corporate debt

        89          89          89          89  

State and municipal debt

        10          10          10          10  

Other

        3          3          3          3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fixed income subtotal

   5     105          110     5     105          110  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Middle market lending

             184     184               184     184  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  Generation  Exelon 

As of March 31, 2016

 Level 1  Level 2  Level 3  Not
subject to
leveling
  Total  Level 1  Level 2  Level 3  Not
subject to
leveling
  Total 

Rabbi trust investments

          

Cash equivalents

  9                9    83                83  

Mutual funds

  17                17    46                46  

Fixed income

                          14            14  

Life insurance contracts

      16            16        60    20        80  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Rabbi trust investments subtotal

  26    16            42    129    74    20        223  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Commodity derivative assets

          

Economic hedges

  1,591    4,849    1,788        8,228    1,591    4,849    1,788        8,228  

Proprietary trading

  31    82    30        143    31    82    30        143  

Effect of netting and allocation of collateral(e)

  (1,739  (3,997  (675      (6,411  (1,739  (3,997  (675      (6,411
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Commodity derivative assets subtotal

  (117  934    1,143        1,960    (117  934    1,143        1,960  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative assets

          

Derivatives designated as hedging instruments

                          42            42  

Economic hedges

      20            20        20            20  

Proprietary trading

  11    2            13    11    2            13  

Effect of netting and allocation of collateral

  (4  (5          (9  (4  (5          (9
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative assets subtotal

  7    17            24    7    59            66  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Other investments

          36        36            36        36  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets

  5,026    3,308    1,888    2,696    12,918    5,720    3,408    1,908    2,696    13,732  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Liabilities

          

Commodity derivative liabilities

          

Economic hedges

  (2,053  (4,688  (885      (7,626  (2,054  (4,688  (1,150      (7,892

Proprietary trading

  (28  (79  (37      (144  (28  (79  (37      (144

Effect of netting and allocation of collateral(e)

  2,089    4,535    826        7,450    2,090    4,535    826        7,451  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Commodity derivative liabilities subtotal

  8    (232  (96      (320  8    (232  (361      (585
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative liabilities

          

Derivatives designated as hedging instruments

      (20          (20      (23          (23

Economic hedges

      (8          (8      (8          (8

Proprietary trading

  (11              (11  (11              (11

Effect of netting and allocation of collateral

  11    5            16    11    5            16  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative liabilities subtotal

      (23          (23      (26          (26
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Deferred compensation obligation

      (30          (30      (131          (131
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total liabilities

  8    (285  (96      (373  8    (389  (361      (742
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total net assets

 $5,034   $3,023   $1,792   $2,696   $12,545   $5,728   $3,019   $1,547   $2,696   $12,990  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

  Generation Exelon  Generation Exelon 

As of December 31, 2014

  Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

Pledged assets for Zion Station decommissioning subtotal(c)

   11    121    184    316    11    121    184    316  

As of December 31, 2015

 Level 1 Level 2 Level 3 Not
subject to
leveling
 Total Level 1 Level 2 Level 3 Not
subject to
leveling
 Total 

Assets

          

Cash equivalents

 $104   $   $   $   $104   $5,766   $   $   $   $5,766  

NDT fund investments

          

Cash equivalents(a)

  219    92            311    219    92            311  

Equities

  3,008            1,894    4,902    3,008            1,894    4,902  

Fixed income

          

Corporate debt

      1,824    242        2,066        1,824    242        2,066  

U.S. Treasury and agencies

  1,323    15            1,338    1,323    15            1,338  

Foreign governments

      61            61        61            61  

State and municipal debt

      326            326        326            326  

Other(b)

      147        390    537        147        390    537  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 
Rabbi trust investments(d)         

Cash equivalents(a)

                   1            1  

Mutual funds(e)

   16            16    46            46  

Fixed income subtotal

  1,323    2,373    242    390    4,328    1,323    2,373    242    390    4,328  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Middle market lending

          428        428            428        428  

Private equity

              125    125                125    125  

Real estate

              35    35                35    35  

Other

              216    216                216    216  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

NDT fund investments subtotal(c)

  4,550    2,465    670    2,660    10,345    4,550    2,465    670    2,660    10,345  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Pledged assets for Zion Station decommissioning

          

Cash equivalents

      17            17        17            17  

Equities

  1    5            6    1    5            6  

Fixed income

          

U.S. Treasury and agencies

  6    2            8    6    2            8  

Corporate debt

      46            46        46            46  

Other

      1            1        1            1  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Fixed income subtotal

  6    49            55    6    49            55  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Middle market lending

          22    105    127            22    105    127  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Pledged assets for Zion Station decommissioning subtotal(d)

  7    71    22    105    205    7    71    22    105    205  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Rabbi trust investments

          

Mutual funds

  17                17    48                48  

Life insurance contracts

      13            13        36            36  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Rabbi trust investments subtotal

   16            16    47            47    17    13            30    48    36            84  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Commodity derivative assets

                   

Economic hedges

   1,667    3,465    1,681    6,813    1,667    3,465    1,681    6,813    1,922    3,467    1,707        7,096    1,922    3,467    1,707        7,096  

Proprietary trading

   201    284    27    512    201    284    27    512    36    64    30        130    36    64    30        130  

Effect of netting and allocation of collateral(f)

   (1,982  (2,757  (557  (5,296  (1,982  (2,757  (557  (5,296

Effect of netting and allocation of collateral(e)

  (1,964  (2,629  (564      (5,157  (1,964  (2,629  (564      (5,157
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Commodity derivative assets subtotal

   (114  992    1,151    2,029    (114  992    1,151    2,029    (6  902    1,173        2,069    (6  902    1,173        2,069  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Interest rate and foreign currency derivative assets

                   

Derivatives designated as hedging instruments

       8        8        31        31                            25            25  

Economic hedges

       12        12        13        13        20            20        20            20  

Proprietary trading

   18    9        27    18    9        27    10    5            15    10    5            15  

Effect of netting and allocation of collateral

   (17  (12      (29  (17  (31      (48  (3  (3          (6  (3  (3          (6
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Interest rate and foreign currency derivative assets subtotal

   1    17        18    1    22        23    7    22            29    7    47            54  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Other investments

           3    3    2        3    5            33        33            33        33  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total assets

   4,558    6,742    2,029    13,329    5,305    6,747    2,029    14,081    4,679    3,473    1,898    2,765    12,815    10,372    3,521    1,898    2,765    18,556  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Liabilities

         

Commodity derivative liabilities

         

Economic hedges

   (2,241  (3,458  (788  (6,487  (2,241  (3,458  (995  (6,694

Proprietary trading

   (195  (295  (42  (532  (195  (295  (42  (532

Effect of netting and allocation of collateral(f)

   2,416    3,557    729    6,702    2,416    3,557    729    6,702  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Commodity derivative liabilities subtotal

   (20  (196  (101  (317  (20  (196  (308  (524
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Interest rate and foreign currency derivative liabilities

         

Derivatives designated as hedging instruments

       (12      (12      (41      (41

Economic hedges

       (2      (2      (103      (103

Proprietary trading

   (14  (9      (23  (14  (9    �� (23

Effect of netting and allocation of collateral

   25    10        35    25    29        54  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Interest rate and foreign currency derivative liabilities subtotal

   11    (13      (2  11    (124      (113

Deferred compensation obligation

       (31      (31      (107      (107
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total liabilities

   (9  (240  (101  (350  (9  (427  (308  (744
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total net assets

  $4,549   $6,502   $1,928   $12,979   $5,296   $6,320   $1,721   $13,337  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

  Generation  Exelon 

As of December 31, 2015

 Level 1  Level 2  Level 3  Not
subject to
leveling
  Total  Level 1  Level 2  Level 3  Not
subject to
leveling
  Total 

Liabilities

          

Commodity derivative liabilities

          

Economic hedges

  (2,382  (3,348  (850      (6,580  (2,382  (3,348  (1,097      (6,827

Proprietary trading

  (33  (57  (37      (127  (33  (57  (37      (127

Effect of netting and allocation of collateral(e)

  2,440    3,186    765        6,391    2,440    3,186    765        6,391  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Commodity derivative liabilities subtotal

  25    (219  (122      (316  25    (219  (369      (563
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative liabilities

          

Derivatives designated as hedging instruments

      (16          (16      (16          (16

Economic hedges

      (3          (3      (3          (3

Proprietary trading

  (12              (12  (12              (12

Effect of netting and allocation of collateral

  12    3            15    12    3            15  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Interest rate and foreign currency derivative liabilities subtotal

      (16          (16      (16          (16
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Deferred compensation obligation

      (30          (30      (99          (99
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total liabilities

  25    (265  (122      (362  25    (334  (369      (678
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total net assets

 $4,704   $3,208   $1,776   $2,765   $12,453   $10,397   $3,187   $1,529   $2,765   $17,878  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

Excludes certainIncludes $38 million and $52 million of cash equivalents consideredreceived from outstanding repurchase agreements at March 31, 2016 and December 31, 2015, respectively, and is offset by an obligation to be held-to-maturity and not reported at fair value.repay upon settlement of the agreement as discussed in (c) below.

(b)

Includes derivative instruments of $(11) million and $(8) million, which have a total notional amount of $1,155 million and $1,236 million at March 31, 2016 and December 31, 2015, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)

Excludes net liabilities of $(34)$(17) million and $(5)$(3) million at September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(d)

Excludes net assets of $0 million and $1 million at March 31, 2016 and December 31, 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(c)

Excludes net assets of $1 million and $3 million at September 30, 2015 and December 31, 2014, respectively. These items consist of net receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d)

Excludes $34 million and $35 million of cash surrender value of life insurance investment at September 30, 2015 and December 31, 2014, respectively, at Exelon Consolidated. Excludes $12 million and $11 million and of cash surrender value of life insurance investment at September 30, 2015 and December 31, 2014, respectively, at Generation.

(e)

The mutual funds held by the Rabbi trusts at Exelon include $45 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at September 30, 2015, and $45 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2014.

(f)

Collateral posted to/(received from)(received) from counterparties totaled $353$350 million, $435$538 million and $245$151 million allocated to Level 1, Level 2 and Level 3 commodity mark-to-market derivatives, respectively, as of September 30, 2015.March 31, 2016. Collateral posted to/(received from)(received) from counterparties, net of collateral paid to counterparties, totaled $434$476 million, $800$557 million and $172$201 million allocated to Level 1, Level 2 and Level 3 commodity mark-to-market derivatives, respectively, as of December 31, 2014.2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value on the utility Registrants’ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2015March 31, 2016 and December 31, 2014:2015:

 

 ComEd PECO BGE  ComEd PECO BGE 

As of September 30, 2015

 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

As of March 31, 2016

 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

Assets

                        

Cash equivalents

 $   $   $   $   $4   $   $   $4   $68   $   $   $68   $   $   $   $   $3   $   $   $3   $43   $   $   $43  

Rabbi trust investments in mutual funds(a)

                  8            8    5            5  

Rabbi trust investments

            

Mutual funds

                  8            8    4            4  

Life insurance contracts

                      11        11                  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Rabbi trust investments subtotal

                  8    11        19    4            4  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total assets

                  12            12    73            73                    11    11        22    47            47  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Liabilities

                        

Deferred compensation obligation

      (7      (7      (11      (11      (4      (4      (8      (8      (12      (12      (3      (3

Mark-to-market derivative liabilities(b)

          (243  (243                                

Mark-to-market derivative liabilities(a)

          (265  (265                                
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total liabilities

      (7  (243  (250      (11      (11      (4      (4      (8  (265  (273      (12      (12      (3      (3
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total net assets (liabilities)

 $   $(7 $(243 $(250 $12   $(11 $   $1   $73   $(4 $   $69   $   $(8 $(265 $(273 $11   $(1 $   $10   $47   $(3 $   $44  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

 

 ComEd PECO BGE  ComEd PECO BGE 

As of December 31, 2014

 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

As of December 31, 2015

 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

Assets

                        

Cash equivalents

 $25   $   $   $25   $12   $   $   $12   $103   $   $   $103   $29   $   $   $29   $271   $   $   $271   $25   $   $   $25  

Rabbi trust investments in mutual funds(a)

                  9            9    5           $5  

Rabbi trust investments

            

Mutual funds

                  8            8    4            4  

Life insurance contracts

                      12        12                  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Rabbi trust investments subtotal

                  8    12        20    4            4  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total assets

  25            25    21            21    108            108    29            29    279    12        291    29            29  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Liabilities

                        

Deferred compensation obligation

      (8      (8      (15      (15      (5      (5      (8      (8      (12      (12      (4      (4

Mark-to-market derivative liabilities(b)

          (207  (207                                

Mark-to-market derivative liabilities(a)

          (247  (247                                
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total liabilities

      (8  (207  (215      (15      (15      (5      (5      (8  (247  (255      (12      (12      (4      (4
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total net assets (liabilities)

 $25   $(8 $(207 $(190 $21   $(15 $   $6   $108   $(5 $   $103   $29   $(8 $(247 $(226 $279   $   $   $279   $29   $(4 $   $25  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

 

(a)

At PECO, excludes $12 million and $14 million of the cash surrender value of life insurance investments at September 30, 2015 and December 31, 2014, respectively.

(b)

The Level 3 balance includesconsists of the current and noncurrent liability of $22$26 million and $221$239 million, respectively, at September 30, 2015, respectively,March 31, 2016, and $20$23 million and $187$224 million, respectively, at December 31, 2014, respectively,2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

PHI, Pepco, DPL and ACE

The following table presents the fair value reconciliation of Level 3tables present assets and liabilities measured and recorded at fair value on PHI’s, Pepco’s, DPL’s and ACE ‘s Consolidated Balance Sheets on a recurring basis duringand their level within the threefair value hierarchy as of March 31, 2016 and nine months ended September 30, 2015 and 2014:December 31, 2015:

 

   Generation  ComEd  Eliminated in
Consolidation
  Exelon 

Three Months Ended
September 30, 2015

 Nuclear
Decommissioning
Trust Fund
Investments
  Pledged Assets
for Zion Station
Decommissioning
  Mark-to-
Market

Derivatives
  Other
Investments
  Total
Generation
  Mark-to-
Market
Derivatives(b)
   Total 

Balance as of June 30, 2015

 $786   $156   $1,021   $30   $1,993   $(223 $   $1,770  

Total realized / unrealized gains (losses)

        

Included in net income

          (48)(a)       (48          (48

Included in noncurrent payables to affiliates

  5                5        (5    

Included in payable for Zion Station decommissioning

      1            1            1  

Included in regulatory assets

                      (20  5    (15

Change in collateral

          90        90            90  

Purchases, sales, issuances and settlements

        

Purchases

  40    5    50    2    97            97  

Sales

      (18  (5      (23          (23

Settlements

  (17              (17          (17

Transfers into Level 3

          69        69            69  

Transfers out of Level 3

          (3      (3          (3
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance as of September 30, 2015

 $814   $144   $1,174   $32   $2,164   $(243 $   $1,921  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the three months ended September 30, 2015

 $(1 $   $181   $   $180   $   $   $180  
   Successor      Predecessor 
   As of March 31, 2016      As of December 31, 2015 

PHI

  Level 1  Level 2  Level 3   Total      Level 1  Level 2  Level 3   Total 

Assets

              

Cash equivalents

  $168   $   $    $168      $42   $   $    $42  

Derivative asset

                               18     18  

Rabbi trust investments

              

Cash equivalents

   73             73       12             12  

Fixed income

       14         14           15         15  

Life insurance contracts

       22    20     42           27    19     46  
  

 

 

  

 

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

Rabbi trust investments subtotal

   73    36    20     129       12    42    19     73  
  

 

 

  

 

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

Total assets

   241    36    20     297       54    42    37     133  
  

 

 

  

��

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

Liabilities

              

Deferred compensation obligation

       (30       (30         (30       (30

Mark-to-market derivative liabilities(a)

   (1           (1     (2           (2

Effect of netting and allocation of collateral

   1             1       2             2  
  

 

 

  

 

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

Mark-to-market derivative liabilities subtotal

                                      
  

 

 

  

 

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

Total liabilities

       (30       (30         (30       (30
  

 

 

  

 

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

Total net assets

  $241   $6   $20    $267      $54   $12   $37    $103  
  

 

 

  

 

 

  

 

 

   

 

 

     

 

 

  

 

 

  

 

 

   

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

  Generation  ComEd  Eliminated in
Consolidation
  Exelon 

Nine Months Ended
September 30, 2015

 Nuclear
Decommissioning
Trust Fund
Investments
  Pledged Assets
for Zion Station
Decommissioning
  Mark-to-
Market

Derivatives
  Other
Investments
  Total
Generation
  Mark-to-
Market
Derivatives(b)
   Total 

Balance as of December 31, 2014

 $691   $184   $1,050   $3   $1,928   $(207 $   $1,721  

Total realized / unrealized gains (losses)

        

Included in net income

  4        (87)(a)       (83          (83

Included in noncurrent payables to affiliates

  20                20        (20    

Included in payable for Zion Station decommissioning

      2            2            2  

Included in regulatory assets

                      (36  20    (16

Change in collateral

          72        72            72  

Purchases, sales, issuances and settlements

        

Purchases

  186    16    107    29    338            338  

Sales

  (8  (58  (10      (76          (76

Settlements

  (83              (83          (83

Transfers into Level 3

  4        80        84            84  

Transfers out of Level 3

          (38      (38          (38
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance as of September 30, 2015

 $814   $144   $1,174   $32   $2,164   $(243 $   $1,921  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2015

 $4   $   $536   $   $540   $   $   $540  
   Pepco  DPL  ACE 

As of March 31, 2016

 Level 1  Level 2  Level 3  Total  Level 1  Level 2  Level 3  Total  Level 1  Level 2  Level 3  Total 

Assets

            

Cash equivalents

 $19   $   $   $19   $   $   $   $   $148   $   $   $148  

Rabbi trust investments

            

Cash equivalents

  43            43                                  

Fixed income

      14        14                                  

Life insurance contracts

      22    20    42                                  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Rabbi trust investments subtotal

  43    36    20    99                                  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets

  62    36    20    118                    148            148  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Liabilities

            

Deferred compensation obligation

      (5      (5      (1      (1                

Mark-to-market derivative liabilities(a)

                  (1          (1                

Effect of netting and allocation of collateral

                  1            1                  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Mark-to-market derivative liabilities subtotal

                                                
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total liabilities

      (5      (5      (1      (1                
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total net assets (liabilities)

 $62   $31   $20   $113   $   $(1 $   $(1 $148   $   $   $148  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

  Pepco  DPL  ACE 

As of December 31, 2015

 Level 1  Level 2  Level 3  Total  Level 1  Level 2  Level 3  Total  Level 1  Level 2  Level 3  Total 

Assets

            

Cash equivalents

 $2   $   $   $2   $   $   $   $   $30   $   $   $30  

Rabbi trust investments

            

Cash equivalents

  11            11                                  

Fixed income

      15        15                                  

Life insurance contracts

      23    19    42                                  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Rabbi trust investments subtotal

  11    38    19    68                                  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total assets

  13    38    19    70                    30            30  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Liabilities

            

Deferred compensation obligation

      (6      (6      (1      (1                

Mark-to-market derivative liabilities(a)

                  (2          (2                

Effect of netting and allocation of collateral

                  2            2                  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Mark-to-market derivative liabilities subtotal

                                                
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total liabilities

      (6      (6      (1      (1                
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total net assets (liabilities)

 $13   $32   $19   $64   $   $(1 $   $(1 $30   $   $   $30  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

IncludesRepresents natural gas futures purchased by DPL as part of a reduction fornatural gas hedging program approved by the reclassification of $229 million and $623 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2015, respectively.

(b)

Includes $19 million of decreases in fair value and a reduction for realized gains due to settlements of $1 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2015. Includes $44 million of decreases in fair value and an increase for realized losses due to settlements of $8 million for the nine months ended September 30, 2015.DPSC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

  Generation  ComEd  Eliminated in
Consolidation
  Exelon 

Three Months Ended
September 30, 2014

 Nuclear
Decommissioning
Trust Fund
Investments
  Pledged Assets
for Zion Station
Decommissioning
  Mark-to-
Market

Derivatives
  Other
Investments
  Total
Generation
  Mark-to-
Market
Derivatives(b)
   Total 

Balance as of June 30, 2014

 $592   $133   $242   $10   $977   $(134 $   $843  

Total realized / unrealized gains (losses)

        

Included in net income

  1        76(a)       77            77  

Included in noncurrent payables to affiliates

  3                3        (3    

Included in payable for Zion Station decommissioning

      (2          (2          (2

Included in regulatory assets

                      (44  3    (41

Change in collateral

          79        79            79  

Purchases, sales, issuances and settlements

        

Purchases

  83    53    12        148            148  

Sales

  (8  (18      (7  (33          (33

Settlements

  (27              (27          (27

Transfers into Level 3

          21        21            21  

Transfers out of Level 3

          1        1            1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance as of September 30, 2014

 $644   $166   $431   $3   $1,244   $(178 $   $1,066  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2014

 $1   $   $163   $   $164   $   $   $164  

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2016 and 2015:

                    Successor       
  Generation  ComEd  PHI(a)     Exelon 

Three Months Ended
March 31, 2016

 NDT Fund
Investments
  Pledged Assets
for Zion Station
Decommissioning
  Mark-to-
Market

Derivatives
  Other
Investments
  Total
Generation
  Mark-to-
Market

Derivatives(b)
  Life
Insurance
Contracts
  Eliminated in
Consolidation
  Total 

Balance as of December 31, 2015

 $670   $22   $1,051   $33   $1,776   $(247 $   $   $1,529  

Included due to merger

                          20        20  

Total realized / unrealized gains (losses)

         

Included in net income

  2        (6)(c)       (4              (4

Included in noncurrent payables to affiliates

  4                4            (4    

Included in payable for Zion Station decommissioning

      2            2                2  

Included in regulatory assets/liabilities

                      (18      4    (14

Change in collateral

          (50      (50              (50

Purchases, sales, issuances and settlements

         

Purchases

  34    1    59    3    97                97  

Sales

          (2      (2              (2

Settlements

  (26              (26              (26

Transfers into Level 3

          2        2                2  

Transfers out of Level 3

          (7      (7              (7
 

 

 

  

 

 

  

 

 

  

 

 

�� 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Balance as of March 31, 2016

 $684   $25   $1,047   $36   $1,792   $(265 $20   $   $1,547  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2016

 $1   $   $219   $   $220   $   $   $   $220  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

 Generation ComEd Eliminated in
Consolidation
  Exelon  Generation ComEd   Exelon 

Nine Months Ended
September 30, 2014

 Nuclear
Decommissioning
Trust Fund
Investments
 Pledged Assets
for Zion Station
Decommissioning
 Mark-to-
Market

Derivatives
 Other
Investments
 Total
Generation
 Mark-to-
Market
Derivatives(b)
 Total 

Balance as of December 31, 2013

 $350   $112   $465   $15   $942   $(193 $   $749  

Three Months Ended
March 31, 2015

 NDT Fund
Investments
 Pledged Assets
for Zion Station
Decommissioning
 Mark-to-
Market

Derivatives
 Other
Investments
 Total
Generation
 Mark-to-
Market

Derivatives(b)
 Eliminated in
Consolidation
 Total 

Balance as of December 31, 2014

 $605   $50   $1,050   $3   $1,708   $(207 $   $1,501  

Total realized / unrealized gains (losses)

                

Included in net income

  5        (284)(a)       (279         $(279  2        (32)(c)       (30          (30

Included in other comprehensive income

                                

Included in noncurrent payables to affiliates

  14                14        (14 $    10                10        (10    

Included in payable for Zion Station decommissioning

      2            2           $2        3            3            3  

Included in regulatory assets

                      15    14   $29                        (34  10    (24

Change in collateral

          257        257           $257            12        12            12  

Purchases, sales, issuances and settlements

                

Purchases

  331    95    27    2    455           $455    28        41        69            69  

Sales

  (10  (43  (6  (7  (66         $(66  (8  (9          (17          (17

Settlements

  (46              (46         $(46  (29              (29          (29

Transfers into Level 3

          (9      (9         $(9  4                4            4  

Transfers out of Level 3

          (19  (7  (26         $(26          (5      (5          (5
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Balance as of September 30, 2014

 $644   $166   $431   $3   $1,244   $(178 $   $1,066  

Balance as of March 31, 2015

 $612   $44   $1,066   $3   $1,725   $(241 $   $1,484  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2014

 $3   $   $(264 $   $(261 $   $   $(261

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2015

 $1   $   $180   $   $181   $   $   $181  

 

(a)

Includes a reductionSuccessor period represents activity from March 24, 2016 through March 31, 2016. See tables below for the reclassification of $87 millionPHI’s predecessor periods, as well as activity for Pepco and $20 million of realized gains due to the settlement of derivative contractsDPL for the three and nine months ended September 30, 2014.March 31, 2016 and 2015.

(b)

Includes $45$25 million of decreases in fair value and an increase for realized losses due to settlements of $1$7 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2014.March 31, 2016. Includes $19$36 million of increasesdecreases in fair value and realized losses due to settlements of $2 million for the three months ended March 31, 2015.

(c)

Includes a reduction for the reclassification of $225 million and $212 million of realized gains due to settlementsthe settlement of $4 millionderivative contracts recorded in results of operations for the ninethree months ended September 30, 2014.March 31, 2016 and 2015, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   Predecessor 
   January 1, 2016 to
March 23, 2016
   Three Months Ended
March 31, 2015
 

PHI

  Preferred
Stock
  Life
Insurance
Contracts
   Preferred
Stock
   Life
Insurance
Contracts
 

Beginning Balance

  $18   $19    $3    $19  

Total realized / unrealized gains (losses)

       

Included in net income

   (18  1          1  

Purchases, sales, issuances and settlements

       

Settlements

                 (1
  

 

 

  

 

 

   

 

 

   

 

 

 

Ending Balance

  $   $20    $3    $19  
  

 

 

  

 

 

   

 

 

   

 

 

 

The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period

  $   $1    $    $1  

   Three Months Ended
March 31, 2016
   Three Months Ended
March 31, 2015
 
   Pepco   DPL   Pepco   DPL 
   Life
Insurance
Contracts
   Life
Insurance
Contracts
   Life
Insurance
Contracts
   Life
Insurance
Contracts
 

Balance as of December 31

  $19    $    $18    $1  

Total realized / unrealized gains (losses)

    

Included in net income

   1          1       

Purchases, sales, issuances and settlements

    

Settlements

                  (1
  

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of March 31

  $20    $    $19    $  
  

 

 

   

 

 

   

 

 

   

 

 

 

The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period

  $1    $    $1    $  

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2015March 31, 2016 and 2014:2015:

 

   Generation  Exelon 
   Operating
Revenues
  Purchased
Power and
Fuel
  Other,  net(a)  Operating
Revenues
  Purchased
Power and
Fuel
  Other,  net(a) 

Total gains (losses) included in net income for the three months ended September 30, 2015

  $(4 $(44 $   $(4 $(44 $  

Total gains (losses) included in net income for the nine months ended September 30, 2015

   (31  (56  4    (31  (56  4  

Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2015

   198    (17  (1  198    (17  (1

Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2015

   538    (2  4    538    (2  4  
   Generation   Exelon 
   Operating
Revenues
   Purchased
Power and
Fuel
  Other,  net(b)   Operating
Revenues
   Purchased
Power and
Fuel
  Other,  net(b) 

Total gains (losses) included in net income for the three months ended March 31, 2016

   49     (55  2     49     (55  2  

Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2016

   254     (35  1     254     (35  1  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   Generation   Exelon 
   Operating
Revenues
  Purchased
Power  and
Fuel
  Other,  net(a)   Operating
Revenues
  Purchased
Power  and
Fuel
  Other,  net(a) 

Total gains (losses) included in net income for the three months ended September 30, 2014

  $70   $6   $1    $70   $6   $1  

Total gains (losses) included in net income for the nine months ended September 30, 2014

   (260  (24  5     (260  (24  5  

Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2014

   142    21    1     142    21    1  

Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2014

   (293  29    3     (293  29    3  
   Generation   Exelon 
   Operating
Revenues
  Purchased
Power  and
Fuel
  Other,  net(b)   Operating
Revenues
  Purchased
Power  and
Fuel
  Other,  net(b) 

Total gains (losses) included in net income for the three months ended March 31, 2015

   (10  (22  2     (10  (22  2  

Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2015

   169    11    1     169    11    1  

   Predecessor         
   PHI   Pepco 
   January 1, 2016
to March 23, 2016
  Three Months
Ended March 31,
2015
   Three Months
Ended March 31,
2016
   Three Months
Ended March 31,
2015
 
   Other, net 

Total (losses) gains included in net income

  $(17 $1    $1    $1  

Change in the unrealized gains (losses) relating to assets and liabilities held

   1    1     1     1  

 

(a)

Successor period represents activity for the period of March 24, 2016 through March 31, 2016.

(b)

Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

Valuation Techniques Used to Determine Fair Value

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.

Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and BGE)ACE).    The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

Preferred Stock Derivative (PHI).    In connection with entering into the PHI Merger Agreement, as further described in Note 16 — Mezzanine Equity, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued quarterlyusing quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore, were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of March 23, 2016. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).The trust fund investments have been established to satisfy Generation’s and CENG’s nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities, Fixed Income and Other. Generation’s and CENG’s NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, which are included in Domestic or Foreign equities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets and are categorized in Level 1. Certain preferred equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. TheWith respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity, balanced and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally holdobjectives such as holding short term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon, Generation, and CENG invest primarily seek to tracktracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. CommingledThe values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are categorized in Level 2 because the fair value ofnot publicly quoted, the funds are based on NAVs per fund share (the unit of account),valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying equity securities.securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

models including cost models, market models and income models. Investments in middle market lendingloans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

Private equity and real estate investments include investmentsthose in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange.exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, and market based comparable data. Since thesedata, and independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable, private equity investments have been categorized as Level 3.observable.

As of September 30, 2015,March 31, 2016, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments and real estate investments of approximately $286 million.$142 million, $42 million, and $135 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

Concentrations of Credit Risk.    Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of March 31, 2016. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of March 31, 2016, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation’s NDT assets.

See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco and BGE)DPL).The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. MutualMoney market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third party. The cash surrenderthird-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs are not observable.have been categorized as Level 3.

Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and ComEd)DPL).     Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter,on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market’s expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 109 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco and BGE)DPL).    The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investmentaccount.investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd)ComEd, PECO, PHI, Pepco and DPL)

Mark-to-Market Derivatives (Exelon, Generation and ComEd).For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk CommitteeRiskCommittee of the Exelon Board of Directors on the scope of the risk management activities. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas coal purchases and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $3.30$2.82 and $0.32$0.25 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’sRegistrants’ mark-to-market derivative assets and liabilities.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 10 —Derivative9 — Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

The table below discloses the significant inputs to the forward curve used to value these positions.

 

Type of trade

  Fair Value at
September 30,
2015
  Valuation
Technique
  Unobservable
Input
 Range

Mark-to-market derivatives — Economic hedges (Generation)(a)(c)

  $935   Discounted

Cash Flow

  Forward power
price
 $11 -  $96(d)
     Forward gas
price
 $1.49 - $9.86(d)
   Option Model  Volatility
percentage
 7% - 130%

Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)

  $(6 Discounted

Cash Flow

  Forward power
price
 $13 -  $89(d)

Mark-to-market derivatives (ComEd)

  $(243 Discounted

Cash Flow

  Forward heat
rate
(b)
 9x - 10x
     Marketability
reserve
 3.5% - 7%
     Renewable
factor
 85% - 126%

(a)

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(b)

Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

(c)

The fair values do not include cash collateral posted on level three positions of $245 million as of September 30, 2015.

(d)

The New England region was not a significant driver for the upper end of the ranges for power and gas as of September 30, 2015.

Type of trade

  Fair Value at
December 31,
2014
  Valuation
Technique
  Unobservable
Input
 Range

Mark-to-market derivatives — Economic hedges (Generation)(a)(c)

  $893   Discounted

Cash Flow

  Forward power
price
 $15 -  $120(d)
     Forward gas
price
 $1.52 -
  $14.02
(d)
   Option
Model
  Volatility
percentage
 8% - 257%

Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)

  $(15 Discounted

Cash Flow

  Forward power
price
 $15 -  $117(d)

Mark-to-market derivatives (ComEd)

  $(207 Discounted

Cash Flow

  Forward heat
rate
(b)
 8x - 9x
     Marketability
reserve
 3.5% - 8%
     Renewable
factor
 86% - 126%

Type of trade

  Fair Value at
March 31,
2016
  Valuation
Technique
  Unobservable
Input
 Range

Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(c)

  $903   Discounted
Cash Flow
  Forward
power price
 $7 — $88
     Forward gas
price
 $0.58 — $7.67
   Option
Model
  Volatility
percentage
 5% — 184%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(c)

  $(7 Discounted
Cash Flow
  Forward
power price
 $9 — $83

Mark-to-market derivatives (Exelon and ComEd)

  $(265 Discounted
Cash Flow
  Forward heat
rate
(b)
 9x — 10x
     Marketability
reserve
 3.5% — 7%
     Renewable
factor
 88% — 129%

 

(a)

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)

Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

(c)

The fair values do not include cash collateral posted on level three positions of $172$151 million as of March 31, 2016.

Type of trade

  Fair Value at
December 31,
2015
  Valuation
Technique
  Unobservable
Input
 Range

Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(c)

  $857   Discounted
Cash Flow
  Forward
power price
 $11 — $88
     Forward gas
price
 $1.18 — $8.95
   Option
Model
  Volatility
percentage
 5% — 152%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(c)

  $(7 Discounted
Cash Flow
  Forward
power price
 $13 — $78

Mark-to-market derivatives (Exelon and ComEd)

  $(247 Discounted
Cash Flow
  Forward heat
rate
(b)
 9x — 10x
     Marketability
reserve
 3.5% — 7%
     Renewable
factor
 87% — 128%

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(a)

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)

Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

(c)

The fair values do not include cash collateral held on level three positions of $201 million as of December 31, 2014.

(d)

The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading.2015.

The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).    For middle market lending and certain corporate debt securities and private equity investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

Rabbi Trust Investments — Life insurance contracts (Exelon, Generation, PECO, PHI, Pepco and DPL)For life insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Exelon gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

10.9.    Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange rate risk and interest rate risk related to ongoing business operations.

Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices.

Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge and fair value hedge. For commodity transactions, Generation, no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivative economic hedges related to commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 2223 — Commitments and Contingencies of the Exelon 20142015 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Economic Hedging.    The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generationoperations,generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of September 30, 2015,March 31, 2016, the proportion of expected generation hedged for the major reportable segments was 97%-100%is 96%-99%, 81%-84%,69%-72% and 51%-54%37%-40% for 2015, 2016, 2017 and 2017,2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to ComEd, PECO and BGEthe Utility Registrants to serve their retail load.

On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reductions was approved in March 2014. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K for additional information.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2015 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2015 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

return component for commercial and industrial rate classes. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.

BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.

Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL’s wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up versus the forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to fifty percent (50%) of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The fifty percent (50%) hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its Gas Hedging Program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Because of the DPSC-approved fuel adjustment clause for DPL’s derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE’s wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

Proprietary Trading.    Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 1,9131,220 GWhs and 5,3781,808 GWhs for the three and nine months ended September 30,March 31, 2016 and 2015, respectively, and 3,006 GWhs and 8,129 GWhs for the three and nine months ended September 30, 2014, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and BGEACE do not enter into derivatives for proprietary trading purposes.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and BGE)PHI)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2015,March 31, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $752$1,287 million and $687 million of notional amounts of floating-to-fixed hedges outstanding.outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an approximately $3$1 million decrease in Exelon Consolidated pre-tax income for the ninethree months ended September 30, 2015.March 31, 2016. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign currency hedgesexchange hedge balances as of September 30, 2015.March 31, 2016.

  Generation  Other  Exelon 

Description

 Derivatives
Designated
as Hedging
Instruments
  Economic
Hedges
  Proprietary
Trading(a)
  Collateral
and
Netting(b)
  Subtotal  Derivatives
Designated
as Hedging
Instruments
  Economic
Hedges
  Collateral
and
Netting(b)
  Subtotal  Total 

Mark-to-market derivative assets (current assets)

 $   $11   $10   $(12 $9   $   $   $   $   $9  

Mark-to-market derivative assets (noncurrent assets)

      10    7    (2  15    37            37    52  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market derivative assets

      21    17    (14  24    37            37    61  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Mark-to-market derivative liabilities (current liabilities)

  (9  (6  (10  16    (9                  (9

Mark-to-market derivative liabilities (noncurrent liabilities)

  (12      (5  5    (12                  (12
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market derivative liabilities

  (21  (6  (15  21    (21                  (21
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market derivative net assets (liabilities)

 $(21 $15   $2   $7   $3   $37   $   $   $37   $40  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   Generation  Exelon
Corporate
  Exelon 

Description

  Derivatives
Designated
as Hedging
Instruments
  Economic
Hedges
  Proprietary
Trading(a)
  Collateral
and
Netting(b)
  Subtotal  Derivatives
Designated
as Hedging
Instruments
  Total 

Mark-to-market derivative assets (current assets)

  $   $10   $8   $(5 $13   $   $13  

Mark-to-market derivative assets (noncurrent assets)

       10    5    (4  11    42    53  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market derivative assets

       20    13    (9  24    42    66  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Mark-to-market derivative liabilities (current liabilities)

   (8  (3  (6  9    (8      (8

Mark-to-market derivative liabilities (noncurrent liabilities)

   (12  (5  (5  7    (15  (3  (18
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market derivative liabilities

   (20  (8  (11  16    (23  (3  (26
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market derivative net assets (liabilities)

  $(20 $12   $2   $7   $1   $39   $40  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts withinbetween the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

(b)

Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2014:2015:

 

 Generation Other Exelon   Generation Exelon
Corporate
   Exelon 

Description

 Derivatives
Designated
as Hedging
Instruments
 Economic
Hedges
 Proprietary
Trading(a)
 Collateral
and
Netting(b)
 Subtotal Derivatives
Designated
as Hedging
Instruments
 Economic
Hedges
 Collateral
and
Netting(b)
 Subtotal Total   Derivatives
Designated
as Hedging
Instruments
 Economic
Hedges
 Proprietary
Trading(a)
 Collateral
and
Netting(b)
 Subtotal Derivatives
Designated
as Hedging
Instruments
   Total 

Mark-to-market derivative assets (current assets)

 $7   $7   $20   $(22 $12   $3   $   $   $3   $15    $   $10   $10   $(5 $15   $    $15  

Mark-to-market derivative assets (noncurrent assets)

  1    5    7    (7  6    20    1    (19  2    8         10    5    (1  14    25     39  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

   

 

 

Total mark-to-market derivative assets

  8    12    27    (29  18    23    1    (19  5    23         20    15    (6  29    25     54  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

   

 

 

Mark-to-market derivative liabilities (current liabilities)

  (8  (2  (14  25    1                    1     (8  (2  (9  11    (8       (8

Mark-to-market derivative liabilities (noncurrent liabilities)

  (4      (9  10    (3  (29  (101  19    (111  (114   (8  (1  (3  4    (8       (8
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

   

 

 

Total mark-to-market derivative liabilities

  (12  (2  (23  35    (2  (29  (101  19    (111  (113   (16  (3  (12  15    (16       (16
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

   

 

 

Total mark-to-market derivative net assets (liabilities)

 $(4 $10   $4   $6   $16   $(6 $(100 $   $(106 $(90  $(16 $17   $3   $9   $13   $25    $38  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

   

 

 

 

(a)

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts withinbetween the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(b)

Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

Fair Value Hedges.    For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:

 

   

Income Statement

Location

 Three Months Ended September 30, 
    2015  2014  2015  2014 
    Gain (Loss) on Swaps  Gain (Loss) on Borrowings 

Generation

  Interest expense(a) $   $(4 $   $1  

Exelon

  Interest expense  16    (8  13    (6

  

Income Statement

Location

 Nine Months Ended September 30,   Income  Statement
Location
 Three Months Ended March 31, 
   2015 2014 2015 2014    2016   2015 2016 2015 
   Gain (Loss) on Swaps Gain (Loss) on Borrowings    Gain (Loss) on Swaps Gain (Loss) on Borrowings 

Generation

  Interest expense(a) $(1 $(12 $   $1    Interest expense(a) $    $(1 $   $  

Exelon

  Interest expense  13    (3  8    6    Interest expense  17     9    (15  (7

 

(a)

For the three and nine months ended September 30,March 31, 2015, the loss on Generation swaps included $0 million and $1 million realized in earnings respectively, with an immaterial amount excluded from hedge effectiveness testing. For the three and nine months ended September 30, 2014, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with an $2 million amount excluded from hedge effectiveness testing.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

At September 30,March 31, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $42 million. At December 31, 2015, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $37$25 million. At December 31, 2014, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. During the three and nine months ended September 30,March 31, 2016 and 2015, the impact on the results of operations as a result of the ineffectiveness from fair value hedges was a $3 million and $11$2 million gain respectively. During the three and nine months ended September 30, 2014, the impact on the results of operations as a result of the ineffectiveness from fair value hedges was a $6 million and $14 million gain, respectively.for each period.

Cash Flow Hedges.    During 2014,the first quarter of 2016, Exelon entered into $400$600 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated refinancingissuance of existing debt. The swaps are designated as cash flow hedges. In January 2015, in connection with Generation’s $750At March 31, 2016, Exelon had a $3 million issuancederivative liability related to the swaps.

During the first quarter of five-year Senior Unsecured Notes,2016, Exelon terminated these swaps. As the original forecasted transactions were a seriesentered into $100 million of futurefloating-to-fixed forward starting interest payments over a ten year period,rate swaps to manage a portion of the interest rate exposure associated with an anticipated interest payments are probabledebt issuance. The swap is designated as a cash flow hedge. Exelon terminated the swap during the first quarter of 2016 upon issuance of the debt. Exelon did not to occur. Asrecognize a gain or loss as a result $26 million of anticipated payments were reclassified from Accumulated OCI tothe termination of the swap and an immaterial amount of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income.Income over the term of the debt. See Note10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with athe long-term borrowing. See Note 1314 — Debt and Credit Agreements of the Exelon 20142015 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $501$499 million as of September 30,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

2015March 31, 2016 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At September 30, 2015,March 31, 2016, the subsidiary had a $16$17 million derivative liability related to the swap.

During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Exelon Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 1314 — Debt and Credit Agreements of the Exelon 20142015 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $200$189 million as of September 30, 2015March 31, 2016 and expire in 2020. The swaps are designated as cash flow hedges. At September 30, 2015,March 31, 2016, the subsidiary had a $4$3 million derivative liability related to the swaps.

During the threesecond quarter of 2002, PHI entered into treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002 to manage a portion of its interest rate exposure. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss and ninethe loss was deferred in AOCI. As a result of the PHI Merger, the remaining unamortized deferred loss recorded in AOCI was adjusted to zero through application of purchase accounting.

During the three months ended September 30,March 31, 2015, and 2014, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships werewas immaterial.

Economic Hedges.    During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 1314 — Debt and Credit Agreements of the Exelon 20142015 Form 10-K for additional information regarding the financing. The swaps have a total notional amount of $26 million as of September 30, 2015 and expire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. During the first quarter of 2015,2016, upon the issuance of debt, Generation terminated the swaps. The total notional amount of the swaps were de-designated$25 million. No gain or loss was recognized as a result of the forecastedtransaction was no longer probabletermination of occurring. All future changesthe swaps.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in fair value are reflected in Interest expense. At September 30, 2015, the subsidiary had a $3 million derivative liability related to these swaps, which included an immaterial amount that was amortized to Interest expense after de-designation.millions, except per share data, unless otherwise noted)

During the third quarter of 2012, Constellation Solar Horizon,Horizons, a subsidiary of Exelon Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 1314 — Debt and Credit Agreements of the Exelon 20142015 Form 10-K for additional information regarding the financing. The swap has a notional amount of $25 million as of September 30, 2015 and expires in 2030. This swap was designated as a cash flow hedge. During the first quarter of 2015,2016, upon the swaps were de-designatedissuance of debt, Generation terminated the swap. The total notional amount of the swap was $24 million. No gain or loss was recognized as a result of the forecasted transaction was no longer probabletermination of occurring. All future changes in fair value are reflected in Interest expense. At September 30, 2015, the subsidiary had an immaterial derivative liability related to the swap.

During the second quarter 2015, upon the issuance of debt, Exelon terminated $2,400 million of floating-to-fixed forward starting interest rate swaps. As a result of the termination of the swaps, Exelon realized a $64 million loss during the second quarter of 2015.

At September 30, 2015,March 31, 2016, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $99$137 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commoditiescommodity transactions in currencies other than U.S. dollars.

Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO, BGE, PHI and BGE)DPL)

Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including initial margin on exchange positions, is aggregated in the collateral and netting column. As of September 30, 2015March 31, 2016 and December 31, 2014, $42015, $1 million and $8$3 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).

Cash collateral held by PECO and BGE must be deposited in a non-affiliatenon affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

In the table below, DPL’s economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2015:March 31, 2016:

 

                 Successor   
  Generation ComEd Exelon  Generation ComEd DPL PHI Exelon 

Derivatives

  Economic
Hedges
 Proprietary
Trading
 Collateral
and
Netting(a)
 Subtotal(b) Economic
Hedges(c)
 Total
Derivatives
  Economic
Hedges
 Proprietary
Trading
 Collateral
and
Netting(a)
 Subtotal(b) Economic
Hedges(c)
 Economic
Hedges(d)
 Collateral
and
Netting(a)
 Subtotal Subtotal Total
Derivatives
 

Mark-to-market derivative assets (current assets)

  $3,958   $221   $(3,072 $1,107   $   $1,107   $5,851   $113   $(4,792 $1,172   $   $   $   $   $   $1,172  

Mark-to-market derivative assets (noncurrent assets)

   2,372    42    (1,665  749        749    2,377    30    (1,619  788                        788  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total mark-to-market derivative assets

   6,330    263    (4,737  1,856        1,856    8,228    143    (6,411  1,960                        1,960  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Mark-to-market derivative liabilities (current liabilities)

   (3,719  (213  3,759    (173  (22  (195  (5,570  (104  5,505    (169  (26  (1  1            (195

Mark-to-market derivative liabilities (noncurrent liabilities)

   (2,088  (50  2,011    (127  (221  (348  (2,056  (40  1,945    (151  (239                  (390
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total mark-to-market derivative liabilities

   (5,807  (263  5,770    (300  (243  (543  (7,626  (144  7,450    (320  (265  (1  1            (585
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total mark-to-market derivative net assets (liabilities)

  $523   $   $1,033   $1,556   $(243 $1,313   $602   $(1 $1,039   $1,640   $(265 $(1 $1   $   $   $1,375  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

 

(a)

Exelon, Generation, PHI and GenerationDPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)

Current and noncurrent assets are shown net of collateral of $281$303 million and $150$146 million, respectively, and current and noncurrent liabilities are shown net of collateral of $405$410 million and $197$180 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,033$1,039 million at September 30, 2015.March 31, 2016.

(c)

Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)

Represents natural gas futures purchased as part by DPL as part of a natural gas hedging program approved by the DPSC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

(c)

Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2014:2015:

 

                     Predecessor 
  Generation ComEd Exelon  Generation ComEd Exelon DPL PHI
Corporate
 PHI 

Description

  Economic
Hedges
 Proprietary
Trading
 Collateral
and
Netting(a)
 Subtotal(b) Economic
Hedges(c)
 Total
Derivatives
  Economic
Hedges
 Proprietary
Trading
 Collateral
and
Netting(a)
 Subtotal(b) Economic
Hedges(c)
 Total
Derivatives
 Economic
Hedges(e)
 Collateral
and

Netting(a)
 Subtotal Other(d) Total
Derivatives
 

Mark-to-market derivative assets (current assets)

  $4,992   $456   $(4,184 $1,264   $   $1,264   $5,236   $108   $(3,994 $1,350   $   $1,350   $   $   $   $18   $18  

Mark-to-market derivative assets (noncurrent assets)

   1,821    56    (1,112  765        765    1,860    22    (1,163  719        719                      
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total mark-to-market derivative assets

   6,813    512    (5,296  2,029        2,029    7,096    130    (5,157  2,069        2,069                18    18  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Mark-to-market derivative liabilities (current liabilities)

   (4,947  (468  5,200    (215  (20  (235  (4,907  (94  4,827    (174  (23  (197  (2  2              

Mark-to-market derivative liabilities (noncurrent liabilities)

   (1,540  (64  1,502    (102  (187  (289  (1,673  (33  1,564    (142  (224  (366                    
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total mark-to-market derivative liabilities

   (6,487  (532  6,702    (317  (207  (524  (6,580  (127  6,391    (316  (247  (563  (2  2              
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total mark-to-market derivative net assets (liabilities)

  $326   $(20 $1,406   $1,712   $(207 $1,505   $516   $3   $1,234   $1,753   $(247 $1,506   $(2 $2   $   $18   $18  
  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

 

(a)

Exelon, Generation, PHI and GenerationDPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit.credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)

Current and noncurrent assets are shown net of collateral of $416$352 million and $171$180 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599$480 million and $220$222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406$1,234 million at December 31, 2014.2015.

(c)

Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Cash Flow Hedges (Exelon, Generation and ComEd).    As discussed previously, effective prior to the Constellation merger, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and is reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. As of September 30, 2015, no unrealized balance remains in accumulated OCI to be reclassified by Generation.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three and nine months ended September 30, 2015 and 2014, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.

   Income  Statement
Location
   Total Cash Flow Hedge OCI Activity,
                   Net of Income Tax                  
 
     Generation  Exelon 

Three Months Ended September 30, 2015

    Total Cash
Flow Hedges
  Total Cash  Flow
Hedges
 

Accumulated OCI derivative gain at June 30, 2015

    $(21 $(19

Effective portion of changes in fair value

     (7  (8

Reclassifications from accumulated OCI to net income

   Interest Expense     3    3  
    

 

 

  

 

 

 

Accumulated OCI derivative gain at September 30, 2015

    $(25 $(24
    

 

 

  

 

 

 

   Income  Statement
Location
   Total Cash Flow Hedge OCI Activity,
                   Net of Income Tax                  
 
     Generation  Exelon 

Nine Months Ended September 30, 2015

    Total Cash Flow
Hedges
  Total Cash  Flow
Hedges
 

Accumulated OCI derivative gain at December 31, 2014

    $(18 $(28

Effective portion of changes in fair value

     (13  (18

Reclassifications from accumulated OCI to net income

   Other, net         16(a) 

Reclassifications from accumulated OCI to net income

   Interest Expense     8    8  

Reclassifications from accumulated OCI to net income

   Operating Revenues     (2  (2
    

 

 

  

 

 

 

Accumulated OCI derivative gain at September 30, 2015

    $(25 $(24
    

 

 

  

 

 

 

(a)(d)

Amount is net of related income tax expense of $10 millionPrior to the PHI Merger, PHI recorded derivative assets for the nine months ended September 30,embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 16—Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.

   Income  Statement
Location
   Total Cash Flow Hedge OCI Activity,
                  Net of Income Tax                   
 
     Generation  Exelon 

Three Months Ended September 30, 2014

    Total Cash  Flow
Hedges
  Total Cash  Flow
Hedges
 

Accumulated OCI derivative gain at June 30, 2014

    $45(a)  $47  

Effective portion of changes in fair value

         (3

Reclassifications from accumulated OCI to net income

   Operating Revenues     (16)(b)   (16
    

 

 

  

 

 

 

Accumulated OCI derivative gain at September 30, 2014

    $29(a)  $28  
    

 

 

  

 

 

 

(a)(e)

Excludes $13 millionRepresents natural gas futures purchased as part by DPL as part of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2014 and June 30, 2014.a natural gas hedging program approved by the DPSC.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Cash Flow Hedges (Exelon and Generation).    The tables below provide the activity of AOCI related to cash flow hedges for the three months ended March 31, 2016 and 2015, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.

   Income  Statement
Location
   Total Cash Flow Hedge OCI Activity,
Net of Income Tax
 
     Generation  Exelon 

Three Months Ended March 31, 2016

    Total Cash
Flow Hedges
  Total Cash
Flow Hedges
 

Accumulated OCI derivative loss at December 31, 2015

    $(21 $(19

Effective portion of changes in fair value

     (8  (10

Reclassifications from AOCI to net income

   Interest Expense     3(a)   3(a) 
    

 

 

  

 

 

 

Accumulated OCI derivative loss at March 31, 2016

    $(26 $(26
    

 

 

  

 

 

 

  Income Statement
Location
  Total Cash Flow Hedge OCI Activity,
Net of Income Tax
 
   Generation  Exelon 

Three Months Ended March 31, 2015

  Total Cash
Flow Hedges
  Total Cash
Flow Hedges
 

Accumulated OCI derivative loss at December 31, 2014

  $(18 $(28

Effective portion of changes in fair value

   (6  (11

Reclassifications from AOCI to net income

  Other, net        16(b) 

Reclassifications from AOCI to net income

  Interest Expense    3    3  

Reclassifications from AOCI to net income

  Operating Revenues    (2  (2
  

 

 

  

 

 

 

Accumulated OCI derivative loss at March 31, 2015

  $(23 $(22
  

 

 

  

 

 

 

(b)(a)

Amount is net of related income tax expense of $12$2 million for both the three months ended September 30, 2014.

   Income  Statement
Location
   Total Cash Flow Hedge OCI Activity,
                  Net of Income Tax                   
 
     Generation  Exelon 

Nine Months Ended September 30, 2014

    Total Cash
Flow Hedges
  Total Cash  Flow
Hedges
 

Accumulated OCI derivative gain at December 31, 2013

    $116(a)  $120  

Effective portion of changes in fair value

     (9  (14

Reclassifications from accumulated OCI to net income

   Operating Revenues     (78)(b)   (78
    

 

 

  

 

 

 

Accumulated OCI derivative gain at September 30, 2014

    $29(a)  $28  
    

 

 

  

 

 

 

(a)

Excludes $13 million of losses and $5 million of losses, net of taxes, related to interest rate swaps and treasury locks as of September 30, 2014 and DecemberMarch 31, 2013, respectively.2016.

(b)

Amount is net of related income tax expensebenefit of $52$10 million for the ninethree months ended September 30, 2014.March 31, 2015.

The effect of Exelon’s and Generation’s former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from accumulated OCIAOCI to earnings was a $2 million pre-tax gain for the nine months ended September 30, 2015. There were no gains recognized for the three months ended September 30,March 31, 2015. For the three and nine months ended September 30, 2014, Exelon and Generation recognized a $28 million and $130 million pre-tax gain, respectively. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods relating to energy-related hedges positions as all were de-designated prior to the Constellation merger date.

Economic Hedges (Exelon and Generation).These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps (“swaps(“treasury”) to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed PHI acquisition. For the three and nine months ended September 30,March 31, 2016 and 2015, and2014, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in Operating revenues or Purchased power and fuel expense, or Interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

 

 Generation HoldCo Exelon   Generation Exelon 

Three Months Ended September 30, 2015

 Operating
Revenues
 Purchased
Power
and Fuel
 Interest
Expense
 Total Interest
Expense
 Total 

Three Months Ended March 31, 2016

  Operating
Revenues
 Purchased
Power
and Fuel
 Total Total 

Change in fair value of commodity positions

 $136   $(178 $   $(42 $   $(42  $279   $(127 $152   $152  

Reclassification to realized at settlement of commodity positions

  (143  46        (97      (97   (211  167    (44  (44
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

 

Net commodity mark-to-market gains (losses)

   68    40    108    108  
        

 

  

 

  

 

  

 

 

Change in fair value of treasury positions

   (3      (3  (3

Reclassification to realized at settlement of treasury positions

   (2      (2  (2
  

 

  

 

  

 

  

 

 

Net treasury mark-to-market gains (losses)

   (5      (5  (5
  

 

  

 

  

 

  

 

 

Net mark-to-market gains (losses)

  $63   $40   $103   $103  
  

 

  

 

  

 

  

 

 

   Generation  Exelon
Corporate
  Exelon 

Three Months Ended March 31, 2015

  Operating
Revenues
  Purchased
Power
and Fuel
  Total  Interest
Expense
  Total 

Change in fair value of commodity positions

  $164   $(79 $85   $   $85  

Reclassification to realized at settlement of commodity positions

   (21  87    66        66  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net commodity mark-to-market gains (losses)

   143    8    151        151  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Change in fair value of treasury positions

   13        13    (78  (65

Reclassification to realized at settlement of treasury positions

   (2      (2      (2
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net treasury mark-to-market gains (losses)

   11        11    (78  (67
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net mark-to-market gains (losses)

  $154   $8   $162   $(78 $84  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

  Generation  HoldCo  Exelon 

Three Months Ended September 30, 2015

 Operating
Revenues
  Purchased
Power
and Fuel
  Interest
Expense
  Total  Interest
Expense
  Total 

Net commodity mark-to-market gains (losses)

  (7  (132      (139      (139
      

Change in fair value of treasury positions

  2            2        2  

Reclassification to realized at settlement of treasury positions

  (2          (2      (2
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net treasury mark-to-market gains (losses)

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net mark-to-market gains (losses)

 $(7 $(132 $   $(139 $   $(139
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  Generation  HoldCo  Exelon 

Nine Months Ended September 30, 2015

 Operating
Revenues
  Purchased
Power
and Fuel
  Interest
Expense
  Total  Interest
Expense
  Total 

Change in fair value of commodity positions

 $513   $(163 $   $350   $   $350  

Reclassification to realized at settlement of commodity positions

  (347  249        (98      (98
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net commodity mark-to-market gains (losses)

  166    86        252        252  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Change in fair value of treasury positions

  12            12    36    48  

Reclassification to realized at settlement of treasury positions

  (6          (6  64    58  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net treasury mark-to-market gains (losses)

  6            6    100    106  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net mark-to-market gains (losses)

 $172   $86   $   $258   $100   $358  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  Generation  HoldCo  Exelon 

Three Months Ended September 30, 2014

 Operating
Revenues
  Purchased
Power
and Fuel
  Interest
Expense
  Total  Interest
Expense
  Total 

Change in fair value of commodity positions

 $181   $19   $   $200   $   $200  

Reclassification to realized at settlement of commodity positions

  86    (23      63        63  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net commodity mark-to-market gains (losses)

  267    (4      263        263  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Change in fair value of treasury positions

  5        (3  2    (8  (6

Reclassification to realized at settlement of treasury positions

  (1          (1      (1
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net treasury mark-to-market gains (losses)

  4        (3  1    (8  (7
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net mark-to-market gains (losses)

 $271   $(4 $(3 $264   $(8 $256  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 
  Generation  HoldCo  Exelon 

Nine Months Ended September 30, 2014

 Operating
Revenues
  Purchased
Power
and Fuel
  Interest
Expense
  Total  Interest
Expense
  Total 

Change in fair value of commodity positions

 $(795 $302   $   $(493 $   $(493

Reclassification to realized at settlement of commodity positions

  224    (207      17       $17  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Nine Months Ended September 30, 2014

 Operating
Revenues
  Purchased
Power
and Fuel
  Interest
Expense
  Total  Interest
Expense
  Total 

Net commodity mark-to-market gains (losses)

  (571  95        (476      (476
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Change in fair value of treasury positions

  1        (5  (4  (8  (12

Reclassification to realized at settlement of treasury positions

  (2          (2      (2
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net treasury mark-to-market gains (losses)

  (1      (5  (6  (8  (14
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net mark-to-market gains (losses)

 $(572 $95   $(5 $(482 $(8 $(490
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Proprietary Trading Activities (Exelon and Generation).    For the three and nine months ended September 30,March 31, 2016 and 2015, and 2014, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate and foreign exchange derivative contracts to hedge risk associated with the interest rate componentand foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

 

  Location on Income
Statement
   Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Location on  Income
Statement
  Three Months Ended
March 31,
 
  2015 2014 2015 2014   2016 2015 

Change in fair value of commodity positions

   Operating Revenues    $(4 $(2 $5   $(2  Operating Revenues  $7   $1  

Reclassification to realized at settlement of commodity positions

   Operating Revenues     (2  (10  (8  (17  Operating Revenues   (3  2  
    

 

  

 

  

 

  

 

     

 

  

 

 

Net commodity mark-to-market gains (losses)

   Operating Revenues     (6  (12  (3  (19  Operating Revenues   4    3  
    

 

  

 

  

 

  

 

     

 

  

 

 

Change in fair value of treasury positions

   Operating Revenues     3    1    7        Operating Revenues   (2  4  

Reclassification to realized at settlement of treasury positions

   Operating Revenues     (3      (9  1    Operating Revenues   1    (4
    

 

  

 

  

 

  

 

     

 

  

 

 

Net treasury mark-to-market gains (losses)

   Operating Revenues         1    (2  1    Operating Revenues   (1    
    

 

  

 

  

 

  

 

     

 

  

 

 

Total Net mark-to-market gains (losses)

   Operating Revenues    $(6 $(11 $(5 $(18

Total net mark-to-market gains (losses)

  Operating Revenues  $3   $3  
    

 

  

 

  

 

  

 

     

 

  

 

 

Credit Risk (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2015.March 31, 2016. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tabletables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and BGEACE of $24$19 million, $33$37 million, $35 million, $36 million, $11 million, and $27$8 million as of September 30, 2015,March 31, 2016, respectively.

 

Rating as of September 30, 2015

  Total
Exposure
Before Credit
Collateral
   Credit
Collateral(a)
   Net
Exposure
   Number  of
Counterparties
Greater than  10%
of Net Exposure
   Net Exposure  of
Counterparties
Greater than  10%
of Net Exposure
 

Rating as of March 31, 2016

  Total Exposure
Before Credit
Collateral
   Credit
Collateral(a)
   Net
Exposure
   Number of
Counterparties
Greater than 10%
of Net Exposure
   Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
 

Investment grade

  $1,463    $18    $1,445     1    $444    $1,276    $58    $1,218     1    $436  

Non-investment grade

   55     15     40               71     32     39            

No external ratings

                    

Internally rated — investment grade

   535          535               516     1     515            

Internally rated — non-investment grade

   53     5     48               101     4     97            
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total

  $2,106    $38    $2,068     1    $444    $1,964    $95    $1,869     1    $436  
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

 

Net Credit Exposure by Type of Counterparty

  As of September 30, 2015   As of March 31, 2016 

Financial institutions

  $260    $116  

Investor-owned utilities, marketers, power producers

   867     781  

Energy cooperatives and municipalities

   908     909  

Other

   33     63  
  

 

   

 

 

Total

  $2,068    $1,869  
  

 

   

 

 

 

(a)

As of September 30, 2015,March 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $13$8 million of cash and $25$87 million of letters of credit.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of September 30, 2015,March 31, 2016, ComEd’s net credit exposure to suppliers was immaterial.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

immaterial .

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K for additional information.

PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of September 30, 2015,March 31, 2016, PECO had no net credit exposure to suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 — Regulatory Matters for additional information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of September 30, 2015,March 31, 2016, PECO had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 53 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of September 30, 2015,March 31, 2016, BGE had no net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At September 30, 2015,March 31, 2016, BGE had credit exposure of less than $1$2 million related to off-system sales which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.

Pepco’s, DPL’s and ACE’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL’s and ACE’s net credit exposure. As of March 31, 2016, Pepco’s, DPL’s and ACE’s net credit exposures to suppliers were immaterial.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL’s and ACE’s counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 6 — Regulatory Matters of the PHI 2015 Form 10-K for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of March 31, 2016, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:

 

Credit-Risk Related Contingent Feature

  September 30,
2015
 December 31,
2014
   March 31,
2016
 December 31,
2015
 

Gross Fair Value of Derivative Contracts Containing this Feature(a)

  $(1,533 $(1,433  $(979 $(932

Offsetting Fair Value of In-the-Money Contracts Under Master

Netting Arrangements(b)

   1,302    1,140     728    684  
  

 

  

 

   

 

  

 

 

Net Fair Value of Derivative Contracts Containing This Feature(c)

  $(231 $(293  $(251 $(248
  

 

  

 

   

 

  

 

 

 

(a)

Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

(b)

Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.

(c)

Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Generation had cash collateral posted of $1,065$1,063 million and letters of credit posted of $474$519 million and cash collateral held of $16 million and letters of credit held of $96 million as of March 31, 2016 for external counterparties with derivative positions. Generation had cash collateral posted of $1,267 million and letters of credit posted of $497 million and cash collateral held of $21 million and letters of credit held of $40 million as of September 30, 2015 for external counterparties. Generation had cash collateral posted of $1,497 million and letters of credit posted of $672 million and cash collateral held of $77 million and letters of credit held of $24$78 million at December 31, 20142015 for external counterparties.counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $2.1$1.9 billion and $2.4$2.0 billion as of September 30, 2015March 31, 2016 and December 31, 2014,2015, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of September 30, 2015,March 31, 2016, Generation and Exelon’s swaps were in an asset position, with a fair value of $3$1 million and $40 million, respectively.

See Note 2425 — Segment Information of the Exelon 20142015 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of September 30, 2015,March 31, 2016, ComEd held no collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2015,March 31, 2016, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of March 31, 2016, it would have been required to post approximately $17 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K for additional information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2015,March 31, 2016, PECO was not required to post collateral for any of these

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

agreements. If PECO lost its investment grade credit rating as of September 30, 2015,March 31, 2016, PECO could have been required to post approximately $18$22 million of collateral to its counterparties.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2015,March 31, 2016, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2015,March 31, 2016, BGE could have been required to post approximately $28 million of collateral to its counterparties.

Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require Pepco to post collateral.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require DPL to post collateral.

(DollarsDPL’s natural gas derivative contracts contain provisions that could require DPL to post collateral in millions, except per share data, unless otherwise noted)an amount equal to the unsecured credit threshold if exceeded when the aggregate fair value of the transactions is in a net loss position. The obligations of DPL are standalone obligations without the guaranty of PHI. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require ACE to post collateral.

11.10.    Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Short-Term Borrowings

Exelon, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool.

The Registrants had PHI meets its short-term liquidity requirement primarily through the following amountsissuance of commercial paper, borrowings outstanding asshort-term notes and the Exelon intercompany money pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of September 30, 2015commercial paper and December 31, 2014:

Commercial Paper Borrowings

  September 30,
2015
   December 31,
2014
 

Exelon Corporate

  $    $  

Generation

          

ComEd

   604     304  

PECO

          

BGE

   50     120  

Credit Facilities

Exelon had bank lines of credit under committed credit facilities at September 30, 2015 for short-term financial needs, as follows:notes.

Type of Credit Facility

  Amount(a)   Expiration Dates  Capacity Type
   (In billions)       

Exelon Corporate

      

Syndicated Revolver(b)

  $0.5    May 2019  Letters of credit and cash

Generation

      

Syndicated Revolver

   5.1    May 2019  Letters of credit and cash

Syndicated Revolver

   0.2    August 2018  Letters of credit and cash

Bilateral

   0.3    December 2015 and March 2016  Letters of credit and cash

Bilateral

   0.1    January 2017  Letters of credit

Bilateral

   0.1    October 2015  Letters of credit and cash

ComEd

      

Syndicated Revolver

   1.0    March 2019  Letters of credit and cash

PECO

      

Syndicated Revolver(b)

   0.6    May 2019  Letters of credit and cash

BGE

      

Syndicated Revolver(b)

   0.6    May 2019  Letters of credit and cash
  

 

 

     

Total

  $8.5      
  

 

 

     

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of September 30, 2015, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $16 million, $21 million and $1 million, respectively.

(b)

Syndicated revolvers include credit facility commitments of $22 million, $27 million and $27 million for Exelon Corporate, PECO and BGE, respectively, which expire in August 2018.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Commercial Paper

The Registrants had the following amounts of commercial paper borrowings outstanding as of March 31, 2016 and December 31, 2015:

Commercial Paper Borrowings

  March 31,
2016
   December 31,
2015
 

Generation

  $1,378    $  

ComEd

   643     294  

BGE

   150     210  

PHI Corporate

   442     484  

Pepco

        64  

DPL

   75     105  

ACE

        5  

Short-Term Loan Agreements

On July 30, 2015, PHI entered into a $300 million term loan agreement. The net proceeds of the loan were used to repay PHI’s outstanding commercial paper and for general corporate purposes. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95%, and all indebtedness thereunder is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before July 28, 2016. On April 4, 2016, PHI repaid $300 million of its term loan in full.

On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI’s outstanding commercial paper, and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the Loan Agreement, must be repaid in full on or before March 27, 2017. The loan agreement is reflected in Exelon’s and PHI’s Consolidated Balance Sheets within Short-term borrowings.

On February 22, 2016, Generation and EDF entered into separate member revolving promissory notes with CENG to finance short-term working capital needs. The notes are scheduled to mature on January 31, 2017 and bear interest at a variable rate equal to LIBOR plus 1.75%. As of September 30, 2015, there were no borrowingsMarch 31, 2016, $25 million was outstanding under the Registrants’ credit facilities.each note. The $25 million note outstanding between Generation and CENG is eliminated in consolidation and therefore not reflected in Exelon’s or Generation’s Consolidated Balance Sheets. The $25 million note with EDF is reflected in Exelon’s and Generation’s Consolidated Balance Sheet within Short-term borrowings.

Credit Agreements

On October 23, 2015,January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility, scheduled to mature in January of 2019. This facility will solely be utilized by Generation to issue lines of credit. This facility does not back Generation’s commercial paper program.

On April 1, 2016, the credit agreement for CENG’s $100 million bilateral CENG credit facility was amended and extended for an additional two years.to increase the overall facility size to $200 million. This facility has beenis utilized by CENG to fund working capital and capital projects. ThisThe facility does not back Generation’s commercial paper program.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Variable Rate Demand Bonds

As of March 31, 2016 and BGE’s credit agreements bear interest at aDecember 31, 2015, $105 million in variable rate based upon eitherdemand bonds issued by DPL were outstanding and are included in the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. Exelon Corporate, Generation, ComEd, PECOLong-term debt due within one year on Exelon’s, PHI’s and BGE have adders of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratingsDPL’s Consolidated Balance Sheet. See Note 10 — Debt of the borrower.PHI 2015 Form 10-K for additional information.

Long-Term Debt

Issuance of Long-Term Debt

During the ninethree months ended September 30, 2015,March 31, 2016, the following long-term debt was issued:

 

Company

 Type Interest Rate  Maturity Amount  

Use of Proceeds

Exelon Corporate

 Senior Unsecured
Notes(a)
  1.55%   June 9, 2017 $550   Finance a portion of the pending acquisition of PHI and related costs and expenses, and for general corporate purposes

Exelon Corporate

 Senior Unsecured
Notes(a)
  2.85%   June 15, 2020 $900   Finance a portion of the pending acquisition of PHI and related costs and expenses, and for general corporate purposes

Exelon Corporate

 Senior Unsecured
Notes (a)
  3.95%   June 15, 2025 $1,250   Finance a portion of the pending acquisition of PHI and related costs and expenses, and for general corporate purposes

Exelon Corporate

 Senior Unsecured
Notes (a)
  4.95%   June 15, 2035 $500   Finance a portion of the pending acquisition of PHI and related costs and expenses, and for general corporate purposes

Exelon Corporate

 Senior Unsecured
Notes (a)
  5.10%   June 15, 2045 $1,000   Finance a portion of the pending acquisition of PHI and related costs and expenses, and for general corporate purposes

Exelon Corporate

 Long Term
Software License
Agreement
  3.95%   May 1, 2024 $111   Procurement of software licenses

Generation

 Senior Unsecured
Notes (b)
  2.95%   January 15, 2020 $750   Fund the optional redemption of Exelon’s $550 million, 4.550% Senior Notes and for general corporate purposes

Generation

 AVSR DOE
Nonrecourse
Debt
  2.29 - 2.96%   January 5, 2037 $39   Antelope Valley solar development

Company

 Type Interest Rate  Maturity Amount  

Use of Proceeds

Generation

 Albany Green Energy
Project Financing
  LIBOR + 1.25%   November 17, 2017 $32   Albany Green Energy biomass generation development

Generation

 Renewable Power
Generation
Nonrecourse Debt
  4.11%   March 31, 2035 $150   Paydown long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes.

On April 7, 2016, Exelon issued and sold $1.8 billion in aggregate principal amount of notes consisting of $300 million of 2.45% Notes due 2021, $750 million of 3.40% Notes due 2026 and $750 million of 4.45% Notes due 2046. A portion of the proceeds of the notes will be used to repay commercial paper issued by PHI and for general corporate purposes, which may include the repayment of outstanding indebtedness.

Retirement and Redemptions of Long-Term Debt

During the three months ended March 31, 2016, the following long-term debt was retired and/or redeemed:

Company

 

Type

 Interest Rate  Maturity Amount 

Generation

 AVSR DOE Nonrecourse Debt  2.29 - 3.56%   January 5, 2037 $5  

Generation

 Continental Wind Nonrecourse Debt  6.00%   February 28, 2033 $15  

Generation

 CEU Upstream Nonrecourse Debt  LIBOR + 2.75%   January 14, 2019 $7  

Generation

 ExGen Texas Power Nonrecourse Debt  5.00%   September 18, 2021 $2  

Generation

 Sacramento PV Energy Nonrecourse Debt  2.58%   December 31, 2030 $33  

Generation

 Constellation Solar Horizons Nonrecourse Debt  2.56%   September 7, 2030 $32  

Generation

 Kennett Square Capital Lease  7.83%   September 20, 2020 $1  

ACE

 ACE Funding Transition Bonds  5.55%   October 20, 2023 $8  

ACE

 ACE Funding Transition Bonds  5.05%   October 20, 2020 $3  

On April 1, 2016, BGE paid down $1 million of principal of its 5.72% Rate Stabilization Bonds due 2016 and $38 million of principal of its 5.82% Rate Stabilization Bonds due 2017.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Company

 Type Interest Rate  Maturity Amount  

Use of Proceeds

Generation

 Energy Efficiency
Project Financing
  3.71%   October 1, 2035 $42   Funding to install energy conservation measures in Coleman, Florida

Generation

 Energy Efficiency
Project Financing
  3.55%   November 15, 2016 $19   Funding to install energy conservation measures in Frederick, Maryland

Generation

 Tax Exempt
Pollution Control
Revenue Bonds
(c)
  2.50 - 2.70%   2019 - 2020 $435   General corporate purposes

Generation

 Albany Green
Energy Project
Financing
  LIBOR + 1.25%   November 17, 2017 $74   Albany Green Energy biomass generation development

ComEd

 Mortgage Bonds
Series 118
  3.70%   March 1, 2045 $400   Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes

(a)

In connection with the issuance of PHI acquisition financing, Exelon terminated its interest rate swaps that had been designated as cash flow hedges. See Note 10 — Derivative Financial Instruments for further information.

(b)

In connection with the issuance of Senior Unsecured Notes, Exelon terminated floating-to-fixed interest rate swaps that had been designated as cash flow hedges. See Note 10 — Derivative Financial Instruments for further information on the swap termination.

(c)

The Tax Exempt Pollution Control Revenue Bonds have a mandatory put date that ranges from March 1, 2019—September 1, 2020.

On OctoberApril 5, 2015, PECO issued $3502016, Generation paid down $1 million aggregateof principal amount of its First2.29% - 3.56% AVSR DOE Nonrecourse debt.

On April 15, 2016, Generation paid down $10 million of principal of its 5.25% ExGen Renewables I Nonrecourse debt.

On April 20, 2016, ACE paid down $8 million of principal of its 5.55% ACE Funding Transition Bonds and Refunding Mortgage Bonds, 3.15% Series, maturing$3 million of principal of its 5.05% ACE Funding Transition Bonds.

CEU Upstream Nonrecourse Debt

In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserve based lending agreement (RBL) associated with certain Upstream oil and gas properties that it owns. The lenders do not have recourse against Exelon or Generation in the event of default pursuant to the RBL. Borrowings under this arrangement are secured by the assets and equity of CEU Holdings The commitment level can be decreased if the assets no longer support the current borrowing base, which may result in repayment of a portion or all of the outstanding balance, or potential foreclosure of the assets. The commitment can be increased up to $500 million if the assets support a higher borrowing base and CEU Holdings is able to obtain additional commitments from lenders. Calculations of the borrowing base are impacted by projected production and commodity prices. The facility was amended and extended on October 15, 2025.January 14, 2014 through January 2019. As of December 31, 2015, $68 million was outstanding under the facility with interest payable monthly at a variable rate equal to LIBOR plus 2.50% and the borrowing base committed under the facility was $85 million.

In February 2016, as part of their semi-annual borrowing base re-determination testing, the RBL lenders notified CEU Holdings that the RBL borrowing base was decreased to $45 million, resulting in a “borrowing base deficiency” under the RBL of $23 million. Given the decline in value of the Upstream assets resulting from lower commodity prices, CEU Holdings chose not to provide the lenders with a formal plan for curing the borrowing base deficiency by March 31, 2016, as was required by the RBL. The proceedslenders have sent CEU Holdings a notice of event of default and demand for cure. CEU Holdings is currently in discussions with the lenders regarding the resolution of the matter. The resolution could include negotiating a forbearance agreement that would provide for the potential sale of Upstream assets in order to wind down the Upstream business of CEU Holdings. Consistent with these discussions, the RBL lenders have not yet accelerated the debt outstanding under the RBL. However, on March 31, 2016, $7 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $61 million with interest payable monthly at a variable rate equal to LIBOR plus 2.75% and a borrowing base deficiency under the RBL of $16 million. The outstanding debt balance of $61 million was classified within Long-term debt due within one year on Exelon’s and Generation’s Consolidated Balance Sheets. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K and Note 6 — Impairment of Long-Lived Assets for additional information.

Other Financing Activities

Accounts Receivable Agreement

In February 2016, PES entered into an accounts receivable sales agreement with a financing institution in which PES will borrow approximately $41 million to complete the construction of an energy efficiency project that is expected to be used for general corporate purposes.completed in 2018. Pursuant to the assignment of PES’ rights to the customer receivables to the financing institution, upon customer acceptance of the energy efficiency project, the customer will pay the financing institution over a 16 year period. At March 31, 2016, PES has borrowed $3 million under the contract which is classified as Long-term debt due within one year on Exelon’s and Generation’s Consolidated Balance Sheet.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Merger Financing11.    Income Taxes (All Registrants)

In May 2014, concurrentlyThe effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:

     Successor  Predecessor 
  Three Months Ended March 31, 2016  March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
 
   Exelon  Generation  ComEd  PECO  BGE  Pepco(a)  DPL(a)  ACE(a)  PHI(a)  PHI 

U.S. Federal statutory rate

  35.0  35.0  35.0  35.0  35.0  35.0  35.0  35.0  35.0  35.0

Increase (decrease) due to:

          

State income taxes, net of Federal income tax benefit (b)

  (1.1  3.7    5.1    1.0    5.2    (2.5  (2.7  5.9    5.4    11.9  

Qualified nuclear decommissioning trust fund income

  5.6    4.2                                  

Domestic production activities deduction

                                        

Health care reform legislation

                                        

Amortization of investment tax credit, including deferred taxes on basis difference

  (1.6  (1.0  (0.3  (0.1  (0.1      0.1    0.2        (0.9

Plant basis differences

  (5.5      (0.1  (9.3  (0.6  2.8    0.7    0.6        (13.5

Production tax credits and other credits

  (5.1  (3.9                                

Non-controlling interest

  0.5    0.3                                  

Merger expenses

  33.6                    (16.5  (22.1  (17.0  (15.1  11.1  

Other

  (2.0  (1.6  0.4    (0.9          0.1    0.1    0.2    3.6  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Effective income tax rate

  59.4  36.7  40.1  25.7  39.5  18.8  11.1  24.8  25.5  47.2
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

   Three Months Ended March 31, 2015 
                 Predecessor          
   Exelon  Generation  ComEd  PECO  BGE  PHI  Pepco  DPL  ACE 

U.S. Federal statutory rate

  35.0  35.0  35.0  35.0  35.0  35.0  35.0  35.0  35.0

Increase (decrease) due to:

         

State income taxes, net of Federal income tax benefit

  2.6    2.7    5.0    1.2    5.3    7.2    5.3    5.7    5.9  

Qualified nuclear decommissioning trust fund income

  1.9    3.0                              

Domestic production activities deduction

  (2.2  (3.4                            

Health care reform legislation

                  0.2                  

Amortization of investment tax credit, including deferred taxes on basis difference

  (0.9  (1.4  (0.3  (0.1      (0.5  (0.1  (0.2  (1.4

Plant basis differences

  (1.3      (0.3  (6.7  (0.3  (4.9  (8.5  (0.9  (2.8

Production tax credits and other credits

  (1.8  (2.8                            

Non-controlling interest

  (0.7  (1.1                            

Other

  0.4    (0.2  0.2        0.2    (0.7  (0.1      (1.0
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Effective income tax rate

  33.0  31.8  39.6  29.4  40.4  36.1  31.6  39.6  35.7
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(a)

Pepco, DPL and ACE recognized a loss before income taxes for the three months ended March 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through March 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.

(b)

Includes a remeasurement of uncertain state income tax positions for Pepco and DPL, see below.

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of March 31, 2016 and in connection with entering into the agreement to acquire PHI, December 31, 2015:

                      Successor             
    Exelon   Generation   ComEd  PECO   BGE   PHI   Pepco   DPL   ACE 

March 31, 2016

  $950    $531    $(12 $    $120    $168    $86    $39    $24  
                       Predecessor             
    Exelon   Generation   ComEd  PECO   BGE   PHI   Pepco   DPL   ACE 

December 31, 2015

  $1,101    $534    $142   $    $120    $22    $8    $3    $  

Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facilityand ComEd’s unrecognized tax benefits changed by $328 million and $154 million, respectively, as of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. In June 2015, the remaining $3.2 billion bridge credit facility was terminatedMarch 31, 2016 as a result of Exelon’s issuance of $4.2 billion of long-term debt to fundthe lease termination on the like-kind exchange position discussed below. In addition, as a portion of the purchase price and related costs and expensesresult of the merger, betweenan assessment and remeasurement of certain federal and state uncertain income tax positions resulted in an increase in unrecognized tax benefits at Exelon, PHI, Pepco, DPL and PHIACE of $177 million, $146 million, $78 million, $36 million and for general corporate purposes.

In connection with the $4.2 billion issuance of Senior Unsecured Notes in 2015, the tranches due in 2025, 2035 and 2045 must be redeemed at the principal amount plus a 1% premium of principal upon the earlier of (1) December 31, 2015, if the PHI acquisition is not consummated on or prior to such date, or (2) the date on which the Merger Agreement relating to the PHI acquisition is terminated. Exelon also has the option to redeem those notes earlier at a 1% premium of principal, if Exelon determines that the merger will not be completed before December 31, 2015.

On October 29, 2015, Exelon commenced a private exchange offer (Exchange Offer) to certain eligible holders whereby, for those that take part, the outstanding notes in the 2025, 2035 and 2045 tranches will be exchanged for new notes. The new notes will have substantially the same terms as the outstanding notes, except the outside date with regard to the special redemption provisions is June 30, 2016, rather than December 31, 2015, and under certain circumstances, can be further extended to August 31, 2016. The Exchange Offer’s early participation period terminates on November 13, 2015 and its expiration date is November 30, 2015, unless extended. Following the completion of the Exchange Offer, any remaining notes not exchanged are expected to be redeemed pursuant to the terms of such remaining notes. Upon redemption, Exelon will accelerate amortization of previously capitalized debt issuance costs on such notes. As of September 30, 2015, the total unamortized debt issuance costs for the 2025, 2035 and 2045 notes is $22 million.

Albany Green Energy Project Financing (AGE)

Generation owns 90% of Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 3—Variable Interest Entities for additional information). In the second quarter of 2015, AGE closed the construction financing and executed an Engineering, Procurement and Construction (EPC) contract to construct a biomass-fueled, combined heat and power facility in Albany, GA. The financing will accumulate and accrue interest throughout construction and is due upon substantial completion of the facility, but no later than November 17, 2017.$24 million, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

During the nine months ended September 30, 2014, the following long-term debt was issued:

Company

 Type  Interest Rate  Maturity Amount  Use of Proceeds

Exelon

 Junior Subordinated Notes   2.50%   June 1, 2024 $1,150   Finance a portion of the
acquisition of PHI and
for general corporate
purposes

Generation

 Nuclear Fuel Purchase
Contract
   3.25 - 3.35%   June 30, 2018 $70   Procurement of uranium

Generation

 ExGen Renewables I
Nonrecourse Debt
   LIBOR + 4.25%   February 6, 2021 $300   General corporate
purposes

Generation

 ExGen Texas Power
Nonrecourse Debt
   LIBOR + 4.75%   September 18,
2021
 $675   General corporate
purposes

Generation

 Energy Efficiency Project
Financing
   4.12%   December 31,
2015
 $12   Funding to install
energy conservation
measures in
Washington, DC

Generation

 AVSR DOE Nonrecourse
Debt
   3.06 - 3.14%   January 5, 2037 $125   Antelope Valley solar
development

ComEd

 First Mortgage Bonds
Series 115
   2.15%   January 15, 2019 $300   Refinance maturing
mortgage bonds and
general corporate
purposes

ComEd

 First Mortgage Bonds
Series 116
   4.70%   January 15, 2044 $350   Refinance maturing
mortgage bonds and
general corporate
purposes

PECO

 First and Refunding
Mortgage Bonds
   4.15%   October 1, 2044 $300   Refinance existing
mortgage bonds and
general corporate
purposes

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Retirement and Redemptions of Current and Long-Term Debt

During the nine months ended September 30, 2015, the following long-term debt was retired and/or redeemed:

Company

  

Type

  Interest Rate  Maturity  Amount 

Exelon
Corporate(a)

  Senior Unsecured Notes   4.55%   June 15, 2015  $550  

Exelon Corporate

  Senior Notes   4.90%   June 15, 2015  $800  

Exelon Corporate

  Long Term Software License Agreement   3.95%   May 1, 2024  $1  

Generation(a)

  Senior Unsecured Notes   4.55%   June 15, 2015  $550  

Generation

  CEU Upstream Nonrecourse Debt   LIBOR + 2.25%   January 14, 2019  $9  

Generation

  AVSR DOE Nonrecourse Debt   2.29%-3.56%   January 5, 2037  $12  

Generation

  Kennett Square Capital Lease   7.83%   September 20, 2020  $3  

Generation

  Continental Wind Nonrecourse Debt   6.00%   February 28, 2033  $20  

Generation

  ExGen Texas Power Nonrecourse Debt   LIBOR + 4.75%   September 8, 2021  $5  

Generation

  ExGen Renewables I Nonrecourse Debt   LIBOR + 4.25%   February 6, 2021  $14  

Generation

  Constellation Solar Horizons Nonrecourse Debt   2.56%   September 7, 2030  $1  

Generation

  Sacramento PV Energy Nonrecourse Debt   2.58%   December 31, 2030  $1  

ComEd

  FMB Series 101   4.70%   April 15, 2015  $260  

BGE

  Rate Stabilization Bonds   5.72 April 1, 2016  $37  

(a)

As part of the 2012 Constellation merger, Exelon and subsidiaries of Generation assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon, resulting in intercompany notes payable at Generation and Exelon Corporate.

On October 5, 2015, Generation paid down $10 million of principal of its 2.29-3.56% AVSR DOE Nonrecourse debt.

On October 15, 2015, Generation paid down $10 million of principal of its LIBOR + 4.25% ExGen Renewables I Nonrecourse debt.

During the nine months ended September 30, 2014, the following long-term debt was retired and/or redeemed:

Company

  

Type

  Interest Rate   Maturity  Amount 

Generation

  Senior Unsecured Notes   5.35%    January 15, 2014  $500  

Generation

  Pollution Control Notes   4.10%    July 1, 2014  $20  

Generation

  Continental Wind Nonrecourse Debt   6.00%    February 28, 2033  $20  

Generation

  Kennett Square Capital Lease   7.83%    September 20, 2020  $2  

Generation

  ExGen Renewables I Nonrecourse Debt   3mL + 4.25%    February 6, 2021  $3  

Generation

  AVSR DOE Nonrecourse Debt   2.33% - 3.55%    January 5, 2037  $4  

Generation

  Clean Horizons Solar Nonrecourse Debt   2.56%    September 7, 2030  $1  

Generation

  Sacramento Solar Nonrecourse Debt   2.56%    December 31, 2030  $1  

Generation

  Energy Efficiency Project Financing   4.40%    August 31, 2014  $9  

ComEd

  Mortgage Bonds Series 110   1.63%    January 15, 2014  $600  

ComEd

  Pollution Control Series 1994C   5.85%    January 15, 2014  $17  

BGE

  Rate Stabilization Bonds   5.72%    April 1, 2016  $35  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Net proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds are being used to finance a portion of the acquisition and related costs and expenses for PHI and for general corporate purposes. Each equity unit represents an undivided beneficial ownership interest in Exelon’s 2.50% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017.

At the time of issuance, Exelon determined that the forward equity purchase contract had no value and therefore the entire $1.15 billion of junior subordinated notes were allocated to debt and recorded within Long-term debt on Exelon’s Consolidated Balance Sheet. Additionally, at the time of issuance, the present value of the contract payments of $131 million (“Contract Payment Obligation”) were recorded to Long-term debt, representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments will be accreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income. During 2015, contract payments of $33 million related to the Contract Payment Obligation were included within Retirements of long-term debt in Exelon’s Consolidated Statements of Cash Flows. During 2014, the Contract Payment Obligation was considered a non-cash financing transaction that was excluded from Exelon’s Consolidated Statements of Cash Flows. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method.

For further information about the terms of the remarketing of the junior subordinated notes, see Note 13 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information of the Exelon 2014 Form 10-K.

12.  Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:

For the Three Months Ended September 30, 2015

 Exelon  Generation  ComEd  PECO  BGE 

U.S. Federal statutory rate

  35.0  35.0  35.0  35.0  35.0

Increase (decrease) due to:

     

State income taxes, net of Federal income tax benefit

  2.7    2.1    5.0    1.2    5.3  

Qualified nuclear decommissioning trust fund income

  (5.4  (12.5            

Domestic production activities deduction

  (4.9  (11.6            

Health care reform legislation

                  0.2  

Amortization of investment tax credit, net deferred taxes

  (2.3  (5.2  (0.3  (0.1  (0.2

Plant basis differences

  (1.4      (0.1  (7.0  (0.6

Production tax credits and other credits

  (3.8  (9.0            

Noncontrolling interest

  1.7    3.9              

Statute of limitations expiration

  (6.4  (15.2            

Other

  1.2    0.4    0.3        (0.4
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Effective income tax rate

  16.4  (12.1)%   39.9  29.1  39.3
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

For the Nine Months Ended September 30, 2015

 Exelon  Generation  ComEd  PECO  BGE 

U.S. Federal statutory rate

  35.0  35.0  35.0  35.0  35.0

Increase (decrease) due to:

     

State income taxes, net of Federal income tax benefit

  3.1    2.8    5.2    1.2    5.3  

Qualified nuclear decommissioning trust fund income

  (0.9  (1.6            

Domestic production activities deduction

  (2.8  (4.9            

Health care reform legislation

                  0.2  

Amortization of investment tax credit, net deferred taxes

  (1.2  (1.9  (0.3  (0.1  (0.1

Plant basis differences

  (1.2      (0.1  (7.3  (0.4

Production tax credits and other credits

  (2.2  (3.8            

Noncontrolling interest

      0.1              

Statute of limitations expiration

  (1.6  (2.9            

Other

  0.9    0.6    0.2    0.2    (0.1
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Effective income tax rate

  29.1  23.4  40.0  29.0  39.9
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

For the Three Months Ended September 30, 2014

 Exelon  Generation  ComEd  PECO  BGE 

U.S. Federal statutory rate

  35.0  35.0  35.0  35.0  35.0

Increase (decrease) due to:

     

State income taxes, net of Federal income tax benefit

  3.4    3.7    5.0    0.1    4.6  

Qualified nuclear decommissioning trust fund income

  (0.3  (0.4            

Domestic production activities deduction

  (2.4  (3.2            

Health care reform legislation

          0.2        0.2  

Amortization of investment tax credit, net deferred taxes

  (1.0  (1.2  (0.3  (0.1  (0.3

Plant basis differences

  (0.8          (11.3  0.5  

Production tax credits and other credits

  (1.9  (2.4            

Noncontrolling interest

  (1.2  (1.6            

Statute of limitations expiration

  (3.8  (5.0            

Other

  1.2    0.6    0.1    (0.1  (1.2
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Effective income tax rate

  28.2  25.5  40.0  23.6  38.8
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

For the Nine Months Ended September 30, 2014

 Exelon  Generation  ComEd  PECO  BGE 

U.S. Federal statutory rate

  35.0  35.0  35.0  35.0  35.0

Increase (decrease) due to:

     

State income taxes, net of Federal income tax benefit

  2.0    1.2    5.0    0.3    4.9  

Qualified nuclear decommissioning trust fund income

  2.0    3.6              

Domestic production activities deduction

  (2.7  (4.8            

Health care reform legislation

  0.1        0.2        0.2  

Amortization of investment tax credit, net deferred taxes

  (1.1  (1.7  (0.3  (0.1  (0.3

Plant basis differences

  (1.6      (0.3  (11.0  0.5  

Production tax credits and other credits

  (2.1  (3.7            

Noncontrolling interest

  (1.4  (2.6            

Statute of limitations expiration

  (2.5  (4.4            

Other

  (0.5  (0.7  0.1    0.1    (0.5
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Effective income tax rate

  27.2  21.9  39.7  24.3  39.8
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd, PECO, and BGE have $1,204 million, $660 million, $144 million, $0 million, and $120 million, of unrecognized tax benefits as of September 30, 2015, respectively, and $1,829 million, $1,357 million, $149 million, $44 million, and $0 million, of unrecognized tax benefits as of December 31, 2014, respectively. The unrecognized tax benefits as of September 30, 2015 reflect a decrease at Exelon, Generation, and PECO primarily attributable to the disallowed AmerGen claims discussed below and the resolution of state income tax positions at Generation. The unrecognized tax benefits as of September 30, 2015 reflect an increase at BGE and Generation attributable to a state income tax opportunity. A portion of the benefits associated with uncertain tax positions for utilities, if recognized, may be included in future base rates.

Nuclear Decommissioning Liabilities

AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and disallowed AmerGen’s claims. In early 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. On September 17, 2013, the Court granted the government’s motion denying AmerGen’s claims for refund. In the first quarter of 2014, Exelon filed an appeal of the decision to the United States Court of Appeals for the Federal Circuit. On March 11, 2015, the Federal Circuit affirmed the lower court’s decision to deny AmerGen’s claims for refund. Exelon will not be pursuing further appeals with respect to this issue and, as a result, reduced Generation and PECO’s unrecognized tax benefits by $661 million and $43 million, respectively, in the first quarter of 2015. This change in unrecognized tax benefits had no impact on Exelon, Generation, or PECO’s effective tax rate.

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Like-Kind Exchange

As of September 30, 2015,March 31, 2016, Exelon and ComEd have approximately $394$75 million and $144$(12) million of unrecognized state income tax benefits that could significantly decrease and increase, respectively, within the 12 months after the reporting date as a result of a decision or settlement in the like-kind exchange litigation described below. Exelon and ComEd haveThese unrecognized tax benefits, that, if recognized, would decrease Exelon’s effective tax rate by $71$75 million and increase ComEd’s effective tax rate by $11$12 million.

Settlement of Income Tax Audits and Litigation

As of September 30, 2015,March 31, 2016, Exelon, Generation, BGE, Pepco, and BGEDPL have approximately $261$270 million, $141$67 million, $120 million, $63 million, and $120$20 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits and potential settlements, and expected statute of limitation expirations.settlements. Of the above unrecognized tax benefits, Exelon and Generation have $141$67 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefitbenefits related to BGE, Pepco, and DPL, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

Like-Kind Exchange (Exelon and ComEd)

Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.

Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $90 million for a substantial understatement of tax.

Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon does not believe a settlement is possible.likely. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like-kind exchange position.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison’s deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon’s current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $170$172 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid tax liabilities related to the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the IRS’s assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded.

On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court and the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. While the Tax Court could reach its decision as early as 2016, the litigation could take three to five years if appeals arean appeal is necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision in Consolidated Edison.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. In connection with the termination, Exelon will deposit $260 million with the IRS for its 2014 tax year, including $135 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. The deposit can be redesignated to any tax year, if necessary, and may be used to satisfy any amounts owed as a result of the litigation.

In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, theas of March 31, 2016, potential tax of $460 million and after-tax interest net of the deposit discussed above and$300 million, exclusive of penalties, that could become currently payable as(net of September 30, 2015 may be as much as $560a $65 million of whichdeposit made to the IRS in 2015). Of the above amounts, approximately $165$275 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. Interest will continue to accrue until such time as payment is made. An appeal of an adverse decision in the Tax Court would necessitate either the posting of a bond or the payment of the tax and interest for the tax years before the court. A final appellate decision could take several

In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. On March 31, 2016, Exelon entered into an agreement to terminate its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million. As a result of the lease terminations, any remaining tax gain related to the LKE position taken in 1999 will no longer be deferred. In the event of a successful outcome in the litigation, Exelon will not be required to pay the after-tax interest described in the preceding paragraph ($300 million as of March 31, 2016) but will be required to report the remaining $460 million of tax due on the transaction in Exelon’s 2014 and 2016 tax years. Of that approximately $230 million is attributable to ComEd. The tax liabilities from the terminations will not result in a current year cash outflow due to the utilization of net operating losses and tax credit carryforwards.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Long-Term State Tax Apportionment (Exelon, Generation and PHI)

Exelon and Generation periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon and Generation to update their long-term state tax apportionment include significant changes in tax law and/or significant operational changes, such as the merger with PHI. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they have state income tax obligations, which include Delaware, Illinois, Maryland, New Jersey, Pennsylvania, and Washington D.C., as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of deferred state tax benefit in the amount of $1 million and a state tax expense of $6 million, net of tax, for Exelon and Generation, respectively. Further, Exelon and PHI recorded deferred state tax liabilities of $59 million and $8 million, net of tax, respectively, as part of purchase accounting during the first quarter of 2016.

13.12.    Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20142015 to September 30, 2015:March 31, 2016:

 

Nuclear decommissioning ARO at December 31, 2014(a)

  $6,961  

Net increase due to changes in, and timing of, estimated future cash flows

   831  

Accretion expense

   283  

Costs incurred to decommission retired plants

   (2
  

 

 

 

Nuclear decommissioning ARO at September 30, 2015(a)

  $8,073  
  

 

 

 

Nuclear decommissioning ARO at December 31, 2015(a)

  $8,246  

Accretion expense

   106  

Net increase due to changes in, and timing of, estimated cash flows

   60  
  

 

 

 

Nuclear decommissioning ARO at March 31, 2016(a)

  $8,412  
  

 

 

 

 

(a)

Includes $7$6 million and $8$7 million as the current portion of the ARO at September 30, 2015March 31, 2016 and December 31, 2014 respectively,2015 which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the ninethree months ended September 30, 2015,March 31, 2016, Generation’s total nuclear ARO increased by approximately $1.1 billion, reflecting impacts$60 million primarily driven by a number of ARO updates completedindividually small items, which were included within the estimated costs to decommission the Oyster Creek nuclear unit as a result of the completion of an updated decommissioning cost study received during the first and third quarters of 2015 to reflect changes in amounts and timing of estimated decommissioning cash flows and impacts of year-to-date accretion of the ARO liability due to the passage of time.

In the first quarter of 2015, the ARO liability was increased by $55 million to reflect a purchase accounting adjustment to the fair value of the CENG ARO liability as of April 1, 2014, the date of the consolidation of CENG. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information. The third quarter 2015 annual update further increased the ARO liability by a net $775 million, which was primarily

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

driven by an increase of approximately $550 million for costs expected to be incurred for required site security during the decommissioning periods in which SNF remains onsite and until major reactor components and buildings have been dismantled and removed. This projected increase is based on emerging industry experience at nuclear sites in the planning or early stage of decommissioning indicating greater than originally expected numbers of security personnel required to be on site during these decommissioning periods. Generation will continue to monitor emerging security cost trends, including potential strategies to limit such costs by, for example, optimizing the transfer of SNF when DOE starts taking possession of SNF or increasing the use of dry SNF storage, and will adjust the ARO liability accordingly. The third quarter 2015 adjustment to the ARO includes an increase of $285 million for the impacts of a change implemented in the 2015 annual assessment of Generation’s SNF storage and disposal cost estimation methodology to better align the projected timing of SNF transfers to the DOE with assumed plant shutdown dates. The third quarter 2015 net increase to the ARO further reflects higher assumed probabilities of early retirements of certain economically challenged nuclear plants (See Note 8 — Implications of Potential Early Plant Retirements for additional information) and net increases in the estimated costs for Peach Bottom and Salem nuclear units pursuant to updated decommissioning cost studies received during 2015; partially offset by reductions in estimated cost escalation rates, primarily for labor and energy costs.quarter.

The financial statement impact related to the increase in the ARO due to the changes in, and timing of, estimated cash flows primarily resulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $8 millionThis increase in cost will be amortized over the remaining useful life of the third quarter adjustment resulted in a credit to income,Oyster Creek nuclear unit, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

During the nine months ended September 30, 2014, Generation’s ARO increased by approximately $1.8 billion. The increase is largely drivenset to retire by the recordingend of an ARO on Exelon’s and Generation’s Consolidated Balance Sheets at fair value, including subsequent purchase accounting adjustments, upon consolidation of CENG during the second quarter (see Note 6 — Investment in Constellation Energy Nuclear Group, LLC). The change in the ARO was also driven by an increase in the estimated costs to decommission the Byron and Braidwood nuclear units pursuant to updated decommissioning costs studies received during the third quarter 2014 as part of the annual assessment. These increases in the ARO were partially offset by decreases in the ARO due to reductions in estimated escalation rates, primarily for labor and energy costs. The increase in the ARO due to the changes in, and timing of, estimated cash flows primarily resulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $16 million of the change in the ARO resulted in a credit to income, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.2019.

Nuclear Decommissioning Trust Fund Investments

At September 30, 2015March 31, 2016 and December 31, 2014,2015, Exelon and Generation had NDT fund investments totaling $10,103$10,526 million and $10,537$10,342 million, respectively.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2015March 31, 2016 and 2014:2015:

 

  Exelon and Generation 
  Three Months Ended September 30,  Nine Months Ended September 30, 
       2015            2014            2015            2014      

Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a)

 $(301 $(107 $(385 $126  

Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)

  (218  (41  (274  100  
    Exelon and Generation 
    Three Months Ended March 31, 
    2016   2015 

Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a)

  $79    $48  

Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)

   52     40  

 

(a)

Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)

Excludes $7$2 million and $10 million of net unrealized gainsgain related to the Zion Station pledged assets for the three months ended September 30, 2014March 31, 2016 and $9 million and $27 million of net unrealized gains related to the Zion Station pledged assets for the nine months ended September 30, 2015, and 2014, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.

(c)

Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

Refer to Note 3 — Regulatory Matters and Note 2526 — Related Party Transactions of the Exelon 20142015 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 1516 — Asset Retirement Obligations of the Exelon 20142015 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $82$85 million which is included within the nuclear decommissioning ARO at September 30, 2015.March 31, 2016. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2015March 31, 2016 and December 31, 2014:2015:

 

 Exelon and Generation   Exelon and Generation 
 September 30,
2015
   December 31,
2014
   March 31,
2016
   December 31,
2015
 

Carrying value of Zion Station pledged assets

 $237    $319    $183    $206  

Payable to Zion Solutions(a)

  217     292     166     189  

Current portion of payable to Zion Solutions(b)

  118     137     95     99  

Cumulative withdrawals by Zion Solutions to pay decommissioning and other costs(c)

  757     666  

Cumulative withdrawals by Zion Solutions to pay decommissioning costs(c)

   812     786  

 

(a)

Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.

(b)

Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

(c)

Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT Fundfund earnings.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, Braidwood Unit 1, Braidwood Unit 2, and Byron Unit 2 did not meet the NRC’s minimum funding assurance criteria as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017. The increased security costs discussed above will be taken into consideration, as appropriate and in accordance withOn February 4, 2016, Generation submitted to the regulatory requirements, in Generation’s futureNRC an updated decommissioning funding status reportsreport for Braidwood Units 1 and 2, and Byron Unit 2. This updated report reflected the recently approved license renewals for these units, and showed that the shortfall identified in the March 31, 2015 report has now been resolved and that Generation has provided adequate decommissioning funding assurance for each unit.

On March 31, 2016, Generation submitted its NRC required annual decommissioning funding status report as of December 31, 2015 for reactors that have been shut down or are within five years of shut down except for Zion Station which is included in a separate report to the NRC.NRC submitted by EnergySolutions (see Zion Station Decommissioning above). As of December 31, 2015, Generation does not expect the increased costs to change Generation’s NRC minimumprovided adequate decommissioning funding assurance status.

14.for all of its reactors that have been shut down or are within five years of shut down except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed in Note 16 — Asset Retirement Benefits (Exelon, Generation, ComEd,Obligations of Exelon’s 2015 Form 10-K, the amount collected from PECO and BGE)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees.ratepayers will be adjusted in the next filing to the PaPUC with new rates effective January 1, 2018.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

13.    Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.

Effective March 23, 2016, Exelon became the sponsor of all PHI’s defined benefit pension and other postretirement benefit plans, and assumed PHI’s benefit plan obligations and related assets. As a result, PHI’s benefit plan net obligation and related regulatory assets were transferred to Exelon. The legacy PHI pension and other postretirement benefit plans were remeasured on February 29, 2016, as a result of the short time between the merger close and the end of the first quarter of 2016, using current assumptions, including the discount rate. The valuation is considered preliminary and Exelon may update these amounts in future quarters to reflect assumptions at March 23, 2016.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2015,2016, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2015.2016. This valuation resulted in an increase to the pension obligation of $45$35 million and an increasea decrease to the other postretirement benefit obligation of $57$8 million. Additionally, accumulated other comprehensive loss increased by approximately $27$2 million (after tax), regulatory assets increased by approximately $48$27 million, and regulatory liabilities decreasedincreased by approximately $11$3 million.

The majority of the 20152016 pension benefit cost for legacy Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.94%4.29%. The majority of the 20152016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.46%6.71% for funded plans and a discount rate of 3.92%4.29%.

The 2016 pension benefit costs for the legacy PHI plans are calculated using an expected long-term rate of return on plan assets of 6.50% and a discount rate of 4.18% for the majority of the pension plans. The 2016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.75% and a discount rate of 4.00%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables presenttable presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the three and nine months ended September 30, 2015March 31, 2016 and 2014.2015.

 

   Pension Benefits
Three  Months Ended
September 30,
  Other
Postretirement  Benefits

Three Months Ended
September 30,
 
   2015(a)  2014(a)  2015(a)  2014(a) 

Service cost

  $82   $74   $30   $27  

Interest cost

   178    189    42    42  

Expected return on assets

   (257  (251  (38  (39

Amortization of:

     

Prior service cost (benefit)

   3    3    (43  (44

Actuarial loss

   142    106    20    15  
  

 

 

  

 

 

  

 

 

  

 

 

 

Net periodic benefit cost

  $148   $121   $11   $1  
  

 

 

  

 

 

  

 

 

  

 

 

 

  Pension Benefits
Nine  Months Ended
September 30,
 Other
Postretirement  Benefits

Nine Months Ended
September 30,
   Pension Benefits
Three Months Ended
March 31,
 Other Postretirement Benefits
Three Months Ended

March 31,
 
  2015(b) 2014(b) 2015(b) 2014(b)        2016(a)         2015          2016(a)         2015     

Components of net periodic benefit cost:

     

Service cost

  $245   $218   $89   $90    $78   $82   $26   $30  

Interest cost

   533    561    125    144     190    178    43    42  

Expected return on assets

   (770  (743  (113  (115   (263  (257  (38  (38

Amortization of:

          

Prior service cost (benefit)

   10    10    (130  (79   3    3    (44  (43

Actuarial loss

   427    316    60    35     127    143    14    20  
  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

 

Net periodic benefit cost

  $445   $362   $31   $75    $135   $149   $1   $11  
  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

 

 

(a)

ForPHI net periodic benefit costs for the three months ended September 30, 2015,period prior to the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. CENG amountsmerger are not included in the tables above.

(b)

For the nine months ended September 30, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $8 million and $8 million, respectively. For the period of April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG amounts are included in the tablestable above.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   Predecessor 
   PHI 
   Pension Benefits  Other Postretirement Benefits 
   January 1, 2016 to
March 23, 2016
  Three Months Ended
March 31, 2015
  January 1, 2016 to
March 23, 2016
  Three Months Ended
March 31, 2015
 

Components of net periodic benefit cost:

    

Service cost

 $12   $14   $1   $2  

Interest cost

  26    27    6    6  

Expected return on assets

  (30  (35  (5  (6

Amortization of:

    

Prior service cost (benefit)

          (3  (3

Actuarial loss

  14    16    2    3  
 

 

 

  

 

 

  

 

 

  

 

 

 

Net periodic benefit cost

 $22   $22   $1   $2  
 

 

 

  

 

 

  

 

 

  

 

 

 

The amounts below represent Generation’s, ComEd’s, PECO’s, BGE’sGeneration, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE, BSC and BSC’sPHISCO’s allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenance expense within the Consolidated Statement of Operations and Comprehensive Income during the three and nine months ended September 30, 2015March 31, 2016 and 2014.2015.

 

  Three Months Ended September 30,   Nine Months Ended September 30,   Three Months Ended March 31, 

Pension and Other Postretirement Benefit Costs

      2015           2014           2015           2014           2016           2015     

Generation(a)

  $67    $54    $200    $193  

Exelon

  $136    $160  

Generation

   54     67  

ComEd

   52     33     155     129     41     52  

PECO

   10     7     29     28     8     10  

BGE

   16     17     49     50     16     17  

BSC(b)

   14     11     43     37  

BSC(a)

   14     14  

Pepco(b)

   8     8  

DPL(b)

   5     4  

ACE(b)

   4     4  

PHISCO(a)(b)

   9     8  

    Successor  Predecessor 

Pension and Other Postretirement Benefit Costs

  March 24, 2016
to March 31,
2016
  January 1, 2016
to March 23,
2016
   Three Months
Ended March  31,
2015
 

PHI

  $3   $23    $24  

 

(a)

For the three and nine months ended September 30, 2015, the costs related to CENG were $5 million and $16 million, respectively. For the three months ended September 30, 2014, the costs related to CENG were $5 million. For the period of April 1, 2014 to September 30, 2014, the costs related to CENG were $11 million. CENG amounts are included in the table above.

(b)

These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or BGEACE amounts above.

(b)

Pepco, DPL, ACE and PHISCO’s pension and postretirement benefit costs for the three months ended March 31, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016. PHI, Pepco, DPL, ACE and PHISCO’s predecessor pension and other postretirement benefit costs for the three months ended March 31, 2015 were $24 million, $8 million, $4 million, $4 million and $8 million, respectively. These amounts are not included in Exelon’s net periodic benefit cost for the three months ended March 31, 2015 shown in the components of net periodic cost table of the Defined Benefit Pension and Other Postretirement Benefits section above.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2015March 31, 2016 and 2014:2015:

 

  Three Months Ended
September 30,
   Nine Months Ended
September 30,
   Three Months Ended March 31, 

Savings Plan Matching Contributions

      2015           2014           2015           2014           2016           2015     

Exelon(a)

  $51    $34    $111    $82    $26    $22  

Generation(a)

   27     17     60     41     12     13  

ComEd

   10     8     23     20     6     5  

PECO

   3     2     7     6     2     1  

BGE

   5     3     10     7     1     2  

BSC(b)(a)

   6     4     11     8     5     1  

Pepco(b)

   1     1  

DPL(b)

   1       

PHISCO(a)(b)

   1     2  

    Successor  Predecessor 

Savings Plan Matching Contributions

  March 24, 2016
to March 31,
2016
  January 1, 2016
to March 23,
2016
   Three Months
Ended March 31,
2015
 

PHI

  $   $3    $3  

 

(a)

Includes $4 million and $8 million, respectively, related to CENG for the three and nine months ended September 30, 2015. Includes $1 million related to CENG for the three months ended September 30, 2014 and for the period from April 1, 2014 to September 30, 2014.

(b)

These amounts primarily represent amounts billed to Exelon’sExelon and PHI’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, or BGE, Pepco and DPL amounts above.

(b)

Pepco’s, DPL’s and PHISCO’s matching contributions for the three months ended March 31, 2016 include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the three months ended March 31, 2016.

15.14.    Severance (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.

Ongoing Severance Plans

The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.

For the threeExelon and nine months ended September 30, 2015Generation recorded $2 million and 2014, the Registrants recorded the following$20 million of severance costs (benefits) associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:

   Exelon  Generation  ComEd   PECO   BGE 

Three Months Ended

      

September 30, 2015

  $(3 $(3 $    $    $  

September 30, 2014

   (2  (2              

Nine Months Ended

      

September 30, 2015

  $18   $17   $1    $    $  

September 30, 2014

   4    3    1            

The severance liability balances associated with these ongoing severance benefits as of September 30, 2015 and December 31, 2014 are not material.

16.    Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the ninethree months ended September 30,March 31, 2016 and 2015, and 2014:respectively, within Operating

Nine Months Ended September 30, 2015

 Gains and
(Losses)  on
Hedging

Activity
  Unrealized
Gains and
(Losses) on
Marketable
Securities
  Pension and
Non-Pension
Postretirement
Benefit Plan
Items
  Foreign
Currency
Items
  AOCI of
Equity
Investments
  Total 

Exelon(a)

      

Beginning balance

 $(28 $3   $(2,640 $(19 $   $(2,684
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (18      (29  (17      (64

Amounts reclassified from AOCI(b)

  22        130            152  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  4        101    (17      88  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(24 $3   $(2,539 $(36 $   $(2,596
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Generation(a)

      

Beginning balance

 $(18 $1   $   $(19 $   $(36
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (13          (17      (30

Amounts reclassified from AOCI(b)

  6                    6  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  (7          (17      (24
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(25 $1   $   $(36 $   $(60
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Nine Months Ended September 30, 2015

 Gains and
(Losses)  on
Hedging

Activity
  Unrealized
Gains and
(Losses) on
Marketable
Securities
  Pension and
Non-Pension
Postretirement
Benefit Plan
Items
  Foreign
Currency
Items
  AOCI of
Equity
Investments
  Total 

PECO(a)

      

Beginning balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

                        

Amounts reclassified from AOCI(b)

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. For Generation, the amount includes $1 million for amounts billed by BSC through intercompany allocations for the three months ended March 31, 2016.

Cost Management Program-Related Severance

In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of approximately 500 positions. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated.

Upon Senior Management approval of the cost management targets and initiatives in the first quarter of 2016, Exelon recorded severance benefit costs of $17 million associated with the anticipated position reductions. The final amount of the charge will ultimately depend on the specific employees severed.

For the three months ended March 31, 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

    Exelon   Generation   ComEd   PECO   BGE 

Severance benefits(a)

  $17    $12    $3    $1    $1  

(a)

The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the three months ended March 31, 2016.

Severance Costs Related to the PHI Merger

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration.

For the three months ended March 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

                       Successor             
   Exelon   Generation   ComEd   PECO   BGE   PHI   Pepco   DPL   ACE 

Severance benefits(a)

  $52    $10    $2    $1    $1    $37    $18    $11    $8  

(a)

The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $9 million, $2 million, $1 million, $1 million, $18 million, $11 million and $8 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the three months ended March 31, 2016.

Cash payments under the plan begin in May 2016 and will continue through 2020.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Severance Liability

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:

                 Successor         

Severance Liability

  Exelon  Generation  ComEd   PECO   BGE   PHI   Pepco   DPL   ACE 

Balance at December 31, 2015

  $35   $23   $3    $    $1    $    $    $    $  

Severance charges(a)(b)

   71    7                   51                 

Payments

   (4  (3                                  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at March 31, 2016

  $102   $27   $3    $    $1    $51    $    $    $  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(a)

Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.

(b)

Represents activity from March 24, 2016 to March 31, 2016 for PHI, Pepco, DPL and ACE.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

15.     Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2016 and 2015:

Three Months Ended March 31, 2016

 Gains and
(Losses)
on Cash Flow
Hedges
  Unrealized
Gains and
(Losses) on
Marketable
Securities
  Pension and
Non-Pension
Postretirement
Benefit Plan
Items
  Foreign
Currency
Items
  AOCI of
Equity
Investments
  Total 

Exelon(a)

      

Beginning balance

 $(19 $3   $(2,565 $(40 $(3 $(2,624
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (10  (1  67    6    (3  59  

Amounts reclassified from AOCI(b)

  3        (34          (31
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  (7  (1  33    6    (3  28  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(26 $2   $(2,532 $(34 $(6 $(2,596
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Generation(a)

      

Beginning balance

 $(21 $1   $   $(40 $(3 $(63
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (8          6    (2  (4

Amounts reclassified from AOCI(b)

  3                    3  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  (5          6    (2  (1
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(26 $1   $   $(34 $(5 $(64
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

PECO(a)

      

Beginning balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

                        

Amounts reclassified from AOCI(b)

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

PHI Predecessor(a)

      

Beginning balance January 1, 2016

 $(8 $   $(28 $   $   $(36
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

          2            2  

Amounts reclassified from AOCI(b)

          (1          (1
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

          1            1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance March 23, 2016(c)

 $(8 $   $(27 $   $   $(35
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Three Months Ended March 31, 2015

 Gains and
(Losses) on
Hedging
Activity
  Unrealized
Gains and
(Losses) on
Marketable
Securities
  Pension and
Non-Pension
Postretirement
Benefit Plan
Items
  Foreign
Currency
Items
  AOCI of
Equity
Investments
  Total 

Exelon(a)

     

Beginning balance

 $(28 $3   $(2,640 $(19 $   $(2,684
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (11      (26  (12      (49

Amounts reclassified from AOCI(b)

  17        43            60  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  6        17    (12      11  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(22 $3   $(2,623 $(31 $   $(2,673
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Generation(a)

     

Beginning balance

 $(18 $1   $   $(19 $   $(36
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (6          (12      (18

Amounts reclassified from AOCI(b)

  1                    1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  (5          (12      (17
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(23 $1   $   $(31 $   $(53
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

PECO(a)

     

Beginning balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

                        

Amounts reclassified from AOCI(b)

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

PHI Predecessor(a)

     

Beginning balance

 $(9 $   $(37 $   $   $(46
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

                        

Amounts reclassified from AOCI(b)

          1            1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

          1            1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $(9 $   $(36 $   $   $(45
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

All amounts are net of tax. Amounts in parenthesesparenthesis represent a decrease in accumulated other comprehensive income.AOCI.

(b)

See tables following changes in accumulated other comprehensive incomenext tables for details about these reclassifications.

Nine Months Ended September 30, 2014

 Gains and
(Losses) on
Hedging
Activity
  Unrealized
Gains and
(Losses) on
Marketable
Securities
  Pension and
Non-Pension
Postretirement
Benefit Plan
Items
  Foreign
Currency
Items
  AOCI of
Equity
Investments
  Total 

Exelon(a)

      

Beginning balance

 $120   $2   $(2,260 $(10 $108   $(2,040
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (14  (2  240    (6  11    229  

Amounts reclassified from AOCI(b)

  (78      91        (119  (106
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  (92  (2  331    (6  (108  123  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $28   $   $(1,929 $(16 $   $(1,917
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Generation(a)

      

Beginning balance

 $114   $2   $   $(10 $108   $214  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

  (8  (3      (6  11    (6

Amounts reclassified from AOCI(b)

  (78              (119  (197
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

  (86  (3      (6  (108  (203
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $28   $(1 $   $(16 $   $11  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

PECO(a)

      

Beginning balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

OCI before reclassifications

                        

Amounts reclassified from AOCI(b)

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net current-period OCI

                        
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Ending balance

 $   $1   $   $   $   $1  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(a)(c)

All amounts are netAs a result of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.

(b)

See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI.

ComEd, PECO, BGE, Pepco, DPL and BGEACE did not have any reclassifications out of AOCI to Net income during the three and nine months ended September 30, 2015March 31, 2016 and 2014.2015. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and GenerationPHI during the three and nine months ended September 30, 2015March 31, 2016 and 2014.2015.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Three Months Ended September 30,March 31, 2016

Details about AOCI components

  Items reclassified out of AOCI(a)   

Affected line item in the Statement of
Operations and Comprehensive Income

         Predecessor    
   Three
Months
Ended
March 31,
2016
  Three
Months
Ended
March 31,
2016
  January 1,
2016 to
March 23,
2016
    
   Exelon  Generation  PHI    

Gains and (losses) on cash flow hedges

      

Other cash flow hedges

  $(5 $(5 $    Interest expense
  

 

 

  

 

 

  

 

 

   

Total before tax

   (5  (5      

Tax expense

   2    2        
  

 

 

  

 

 

  

 

 

   

Net of tax

  $(3 $(3 $    Comprehensive income
  

 

 

  

 

 

  

 

 

   
      

Amortization of pension and other postretirement benefit plan items

      

Prior service costs(b)

  $(20 $   $    

Actuarial losses(b)

   76        1    
  

 

 

  

 

 

  

 

 

   

Total before tax

   56        1    

Tax benefit

   (22          
  

 

 

  

 

 

  

 

 

   

Net of tax

  $34   $   $1    
  

 

 

  

 

 

  

 

 

   

Total Reclassifications

  $31   $(3 $1    Comprehensive income
  

 

 

  

 

 

  

 

 

   

Three Months Ended March 31, 2015

 

Details about AOCI components

  Items reclassified out of AOCI(a)  Affected line item in the Statements of
Operations and Comprehensive  Income
   Exelon  Generation   

Gains (losses) on hedging activity

    

Other cash flow hedges

  $(4 $(4 Interest expense
  

 

 

  

 

 

  
   (4  (4 Total before tax
   1    1   Tax benefit
  

 

 

  

 

 

  
  $(3 $(3 Net of tax
  

 

 

  

 

 

  
    

Amortization of pension and other postretirement benefit plan items

    

Prior service costs (b)

  $19   $   

Actuarial losses (b)

   (90     
  

 

 

  

 

 

  
   (71     Total before tax
   28       Tax benefit
  

 

 

  

 

 

  
    
  $(43 $   Net of tax
  

 

 

  

 

 

  

Total Reclassifications for the period

  $(46 $(3 Net of Tax
  

 

 

  

 

 

  

Details about AOCI components

  Items reclassified out of AOCI(a)  

Affected line item in the Statement of
Operations and Comprehensive  Income

         Predecessor   
   Exelon  Generation  PHI   

Gains and (losses) on cash flow hedges

     

Terminated interest rate swaps

  $(26 $   $   Other, net

Energy related hedges

   2    2       Operating revenues

Other cash flow hedges

   (3  (3     Interest expense
  

 

 

  

 

 

  

 

 

  

Total before tax

   (27  (1     

Tax benefit

   10           
  

 

 

  

 

 

  

 

 

  

Net of tax

  $(17 $(1 $   Comprehensive income
  

 

 

  

 

 

  

 

 

  
     

Amortization of pension and other postretirement benefit plan items

     

Prior service costs(b)

  $19   $   $   

Actuarial losses(b)

   (90      (2 
  

 

 

  

 

 

  

 

 

  

Total before tax

   (71      (2 

Tax benefit

   28        1   
  

 

 

  

 

 

  

 

 

  

Net of tax

  $(43 $   $(1 
  

 

 

  

 

 

  

 

 

  

Total Reclassifications

  $(60 $(1 $(1 Comprehensive income
  

 

 

  

 

 

  

 

 

  

Nine Months Ended September 30, 2015COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Details about AOCI components

  Items reclassified out of AOCI(a)  Affected line item in the Statements of
Operations and Comprehensive  Income
   Exelon  Generation   

Gains (losses) on hedging activity

    

Terminated interest rate swaps(c)

  $(26 $   Other, net

Energy related hedges

   2    2   Operating revenues

Other cash flow hedges

   (11  (11 Interest expense
  

 

 

  

 

 

  
    
   (35  (9 Total before tax
   13    3   Tax benefit
  

 

 

  

 

 

  
  $(22 $(6 Net of tax
  

 

 

  

 

 

  
    

Amortization of pension and other postretirement benefit plan items

    

Prior service costs (b)

  $57   $   

Actuarial losses (b)

   (270     
  

 

 

  

 

 

  
   (213     Total before tax
   83       Tax benefit
  

 

 

  

 

 

  
  $(130 $   Net of tax
  

 

 

  

 

 

  

Total Reclassifications for the period

  $(152 $(6 Net of Tax
  

 

 

  

 

 

  

(a)

Amounts in parenthesis represent a decrease in net income.

(b)

This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 13 — Retirement Benefits for additional details).

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three months ended March 31, 2016 and 2015:

   Three Months Ended
March 31,
 
       2016          2015     

Exelon

   

Pension and non-pension postretirement benefit plans:

   

Prior service benefit reclassified to periodic benefit cost

  $7   $8  

Actuarial loss reclassified to periodic cost

   (30  (35

Pension and non-pension postretirement benefit plans valuation adjustment

       17  

Change in unrealized gain/(loss) on cash flow hedges

   3    (2

Change in unrealized loss on equity investments

   2      

Change in unrealized gain on marketable securities

   1      
  

 

 

  

 

 

 

Total

  $(17 $(12
  

 

 

  

 

 

 

Generation

   

Change in unrealized gain on cash flow hedges

  $2   $5  

Change in unrealized loss on equity investments

   2      
  

 

 

  

 

 

 

Total

  $4   $5  
  

 

 

  

 

 

 

   Predecessor 

PHI

  January 1,
2016 to
March 23,
2016
   Three
Months
Ended
March 31,
2015
 

Pension and non-pension postretirement benefit plans:

  

Actuarial loss reclassified to periodic cost

  $    $(1

16.     Mezzanine Equity (Exelon, Generation and PHI)

Contingently Redeemable Noncontrolling Interest (Exelon and Generation)

In November 2015, 2015 ESA Investco, LLC, a wholly owned subsidiary of Generation, entered into an arrangement to sell a portion of its equity to a tax equity investor. Pursuant to the operating agreement, in certain circumstances the equity contributed by the noncontrolling interest holder could be contingently redeemable. These circumstances are outside of the control of Generation and the noncontrolling interest holder resulting in a portion of the noncontrolling interest being considered contingently redeemable and thus presented in mezzanine equity on the consolidated balance sheet.

The following table summarizes the changes in the contingently redeemable noncontrolling interest for the three months ended March 31, 2016:

Balance at December 31, 2015

  $28  

Cash received from noncontrolling interest

   10  

Release of contingency

   (19
  

 

 

 

Balance at March 31, 2016

  $19  
  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Three months ended September 30, 2014Preferred Stock (PHI)

Details about AOCI components

  Items reclassified out of AOCI(a)  Affected line item in the Statements of
Operations and Comprehensive  Income
   Exelon  Generation   

Gains on hedging activity

    

Energy related hedges

  $28   $28   Operating revenues
  

 

 

  

 

 

  
   28    28   Total before tax
   (12  (12 Tax (expense)
  

 

 

  

 

 

  
  $16   $16   Net of tax
  

 

 

  

 

 

  

Amortization of pension and other postretirement benefit plan items

    

Prior service costs(b)

  $19   $   

Actuarial losses(b)

   (61     
  

 

 

  

 

 

  
   (42     Total before tax
   16       Tax benefit
  

 

 

  

 

 

  
  $(26 $   Net of tax
  

 

 

  

 

 

  

Equity investments

    

Reversal of CENG equity method AOCI

  $5   $5   Gain on consolidation of CENG
  

 

 

  

 

 

  
   5    5   Total before tax
   (2  (2 Tax benefit
  

 

 

  

 

 

  
  $3   $3   Net of tax
  

 

 

  

 

 

  

Total reclassifications for the period

  $(7 $19   Net of Tax
  

 

 

  

 

 

  

Nine Months Ended September 30, 2014In connection with the PHI Merger Agreement, Exelon purchased 18,000 originally issued shares of PHI preferred stock for a purchase price of $180 million. PHI excluded the preferred stock from equity at December 31, 2015 since the preferred stock contained conditions for redemption that were not solely within the control of PHI. Management determined that the preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the preferred stock in the event of such a termination were separately accounted for as derivatives. As of December 31, 2015, the fair value of the derivative related to the preferred stock was estimated to be $18 million based on PHI’s updated assessment and was included in current assets with a corresponding increase in preferred stock on the Consolidated Balance Sheet. Immediately prior to the merger date, PHI updated its assessment of the fair value of the derivative and reduced the fair value to zero, recording the $18 million decrease in fair value as a reduction of Other, net in the predecessor period January 1, 2016 to March 23, 2016.

Details about AOCI components

  Items reclassified out of AOCI(a)  Affected line item in the Statements of
Operations and Comprehensive  Income
   Exelon  Generation   

Gains on hedging activity

    

Energy related hedges

  $130   $130   Operating revenues
  

 

 

  

 

 

  
   130    130   Total before tax
   (52  (52 Tax (expense)
  

 

 

  

 

 

  
  $78   $78   Net of tax
  

 

 

  

 

 

  

Amortization of pension and other postretirement benefit plan items

    

Prior service costs(b)

  $29   $   

Actuarial losses(b)

   (178     
  

 

 

  

 

 

  
   (149     Total before tax
   58       Tax benefit
  

 

 

  

 

 

  
  $(91 $   Net of tax
  

 

 

  

 

 

  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Details about AOCI components

  Items reclassified out of AOCI(a)  Affected line item in the Statements of
Operations and Comprehensive  Income
   Exelon  Generation   

Equity investments

    

Sale of equity method investment

  $5   $5   Gain on consolidation of CENG

Reversal of CENG equity method AOCI

   193    193   Gain on consolidation of CENG
  

 

 

  

 

 

  
   198    198   Total before tax
   (79  (79 Tax benefit
  

 

 

  

 

 

  
  $119   $119   Net of tax
  

 

 

  

 

 

  

Total reclassifications for the period

  $106   $197   Net of Tax
  

 

 

  

 

 

  

(a)

All amounts are net of tax. Amounts in parentheses represent a decrease in net income.

(b)

This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 14 — Retirement Benefits for additional details).

(c)

In January 2015, in connection with Generation’s $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income.

The following table presents income tax expense (benefit) allocatedOn March 23, 2016, the preferred stock was cancelled and the $180 million cash consideration previously received by PHI to each component of other comprehensive income (loss) duringissue the three and nine months ended September 30, 2015 and 2014:

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
       2015          2014          2015          2014     

Exelon

     

Pension and non-pension postretirement benefit plans:

     

Prior service benefit reclassified to periodic benefit cost

  $8   $8   $22   $11  

Actuarial loss reclassified to periodic cost

   (35  (24  (105  (69

Pension and non-pension postretirement benefit plans valuation adjustment

       5    17    (153

Change in unrealized (gain) loss on cash flow hedges

   3    15    (3  62  

Change in unrealized income on equity investments

       3        73  

Change in unrealized loss on marketable securities

       1        (1
  

 

 

  

 

 

  

 

 

  

 

 

 

Total

  $(24 $8   $(69 $(77
  

 

 

  

 

 

  

 

 

  

 

 

 

Generation

     

Change in unrealized loss on cash flow hedges

  $3   $13   $4   $57  

Change in unrealized income on equity investments

       3        73  

Change in marketable securities

       1        (1
  

 

 

  

 

 

  

 

 

  

 

 

 

Total

  $3   $17   $4   $129  
  

 

 

  

 

 

  

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

preferred stock was treated as additional merger purchase price consideration.

17.     Common Stock (Exelon)

Equity Securities Offering

In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share and entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreements by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. Use of net proceeds will be to fund the pending acquisition of PHI and related costs and expenses, and for general corporate purposes.

The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS using the treasury stock method. For further information on the transaction, refer to Note 19—Common Stock of the Exelon 2014 Form 10-K.

Concurrent with the June 2014 forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. See Note 11 — Debt and Credit Agreements for further information on the equity units.

18.    Earnings Per Share and Equity (Exelon)

Earnings per Share (Exelon)

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, adjustedincluding shares to include the potentially dilutive effectbe issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs.LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share:

 

   Three Months Ended
September 30,
   Nine Months Ended
September 30,
 
           2015       2014           2015           2014     

Net income attributable to common shareholders

  $629    $993    $1,959    $1,604  
  

 

 

   

 

 

   

 

 

   

 

 

 

Average common shares outstanding — basic

   913     861     879     860  

Potentially dilutive effect of stock options, performance share awards and restricted stock

   2     2     4     3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Average common shares outstanding — diluted

   915     863     883     863  
  

 

 

   

 

 

   

 

 

   

 

 

 
   Three Months Ended
March 31,
 
        2016           2015     

Exelon

    

Net income attributable to common shareholders

  $173    $693  
  

 

 

   

 

 

 

Weighted average common shares outstanding — basic

   923     862  

Assumed exercise and/or distributions of stock-based awards

   2     5  
  

 

 

   

 

 

 

Weighted average common shares outstanding — diluted

   925     867  
  

 

 

   

 

 

 

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 1413 million and 15 million for the three and nine months ended September 30,March 31, 2016 and 2015, and 16 million for the three and nine months ended September 30, 2014.respectively. The number of equity units related to the PHI mergerMerger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 4 million and 2 million for the three and nine months ended September 30, 2015, respectively,March 31, 2016 and 2less than 1 million for the three months ended September 30, 2014 and 1March 31, 2015. Refer to Note 19 — Shareholder’s Equity of the Exelon 2015 Form 10-K for further information regarding the equity units.

Under share repurchase programs, 35 million for the nine months ended September 30, 2014. Additionally, there were no forward units relatedshares of common stock are held as treasury stock with a cost of $2.3 billion as of March 31, 2016. In 2008, Exelon management decided to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three and ninedefer indefinitely any share repurchases.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

months ended September 30, 2015, and approximately 2 million not included for the three months ended September 30, 2014 and 1 million not included for the nine months ended September 30, 2014. Refer to Note 17 — Common Stock for further information regarding the equity units and equity forward units.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of September 30, 2015. In 2008, Exelon management decided to defer indefinitely any share repurchases.

19.18.     Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 2223 of the Exelon 20142015 Form 10-K and Note 16 of the PHI 2015 Form 10-K. See Note 4—Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.

Commitments

Constellation Merger Commitments (Exelon and Generation)

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.

The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement for office space that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. Generation’s total commitments under the lease agreement are $0 million, $5 million, $12 million, $13 million, $13 million, and $285 million, related to 2015, 2016, 2017, 2018, 2019 and thereafter.

The direct investment commitment also includes $575$500 million to $650$600 million relating to Exelon and Generation’s development or assistance in the development of 275 — 300 MWs of new generation in Maryland, which is expected to be completed withinover a period of 10 years. As of March 31, 2016, Exelon and Generation have incurred $353$398 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 160220 MW of the new generation commencing with commercial operations to date. The MDPSC orderOrder contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation now believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the nine and three months ended September 30, 2014.commitment. While this $44 million loss contingency represents Generation’s best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

generating output from a successfully constructed generating plant. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for additional information regarding the Constellation merger commitments.

Equity Investment Commitments (Exelon and Generation)

As part of Generation’s investments in technology development, Generation entershas entered into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. The commitment includes approximately $20 million of in-kind services.services and 100% of 2015 ESA Investco, LLC’s equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 3—Variable Interest Entities for additional details). As of September 30, 2015,March 31, 2016, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:

 

   Total 

2015

  $38  

2016

   276  

2017

   23  

2018

   7  

2019

   2  
  

 

 

 

Total

  $346  
  

 

 

 

Contingencies

Commercial Commitments

The Registrants’ commercial commitments as of September 30, 2015, representing commitments potentially triggered by future events were as follows:

   Exelon  Generation  ComEd  PECO  BGE 

Letters of credit (non-debt)(a)

  $1,078   $1,011   $18   $22   $1  

Guarantees

   5,823(b)   3,159(c)   205(d)   188(e)   263(f) 

Nuclear insurance premiums(g)

   3,057    3,057              
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total commercial commitments

  $9,958   $7,227   $223   $210   $264  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(a)

Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

(b)

Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $650 million at September 30, 2015, which represents the total amount Exelon could be required to fund based on September 30, 2015 market prices.

(c)

Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $475 million at September 30, 2015, which represents the total amount Generation could be required to fund based on September 30, 2015 market prices.

(d)

Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.

(e)

Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

    Total 

2016(a)

  $271  

2017

   21  

2018

   7  
  

 

 

 

Total

  $299  
  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

(f)(a)

Primarily reflects fullThe noncontrolling interest holder of 2015 ESA Investco, LLC will contribute up to $132 million in support of a portion of the remaining equity commitment.

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of March 31, 2016, representing commitments potentially triggered by future events were as follows:

                 Successor          
  Exelon  Generation  ComEd  PECO  BGE  PHI  Pepco  DPL  ACE 

Letters of credit (non-debt)(a)

 $1,628   $1,560   $16   $22   $2   $1   $   $   $  

Surety bonds(b)

  950    852    10    9    10    16    9    4    3  

Financing trust guarantees

  628        200    178    250                  

Nuclear insurance premiums(c)

  3,056    3,056                              

Guaranteed lease residual values(d)

  20                    20    6    8    5  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total commercial commitments

 $6,282   $5,468   $226   $209   $262   $37   $15   $12   $8  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

(a)

Letters of credit (non-debt) — Exelon and unconditional guaranteescertain subsidiaries maintain non-debt letters of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.credit to provide credit support for certain transactions as requested by third parties.

(g)(b)

Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)

Nuclear insurance premiums — Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

(d)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $53 million, $13 million of which is a guarantee by Pepco, $17 million by DPL and $14 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Nuclear Insurance (Exelon and Generation)

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of September 30, 2015,March 31, 2016, the current liability limit per incident was $13.4is $13.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of September 30, 2015,March 31, 2016, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

participation in a retrospective rating plan for power reactors (currently 102103 reactors) resulting in an additional $12.9$13.1 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG’s related liability.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4$13.5 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price AndersonPrice-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 6 —5— Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2015 Form 10-K for additional information on Generation’s operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Environmental Issues(All Registrants)

General.    The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

ComEd, PECO, BGE and BGEDPL have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

 

ComEd has identified 42 sites, 17 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 25 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2020.

 

PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2021.

 

BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. An investigation of an additionalOne former gas purification site was completed during the first quarter of 2015is currently under investigation at the direction of the MDE. For more information, see the discussion of the Riverside site below.

DPL has identified 2 sites, 1 of which the remediation has been completed and approved by the MDE. Remediation work at the remaining site has been completed and an application has been submitted to the Delaware Department of Natural Resources and Environmental Control for approval.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. ComEd and PECO have recorded regulatory assets for the recovery of these costs. See Note 5 —

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Regulatory Matters for additional information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.

As of September 30, 2015March 31, 2016 and December 31, 2014,2015, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

 

September 30, 2015

  Total Environmental
Investigation and
Remediation Reserve
   Portion of Total Related to
MGP Investigation and
Remediation
 

March 31, 2016

  Total Environmental
Investigation and
Remediation Reserve
   Portion of Total Related to
MGP Investigation and
Remediation(a)
 

Exelon

  $376    $309    $399    $298  

Generation

   63          68       

ComEd

   269     268     263     261  

PECO

   41     39     36     34  

BGE

   3     2     3     2  

PHI (Successor)

   29     1  

Pepco

   25       

DPL

   3     1  

ACE

   1       

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

December 31, 2014

  Total Environmental
Investigation and
Remediation Reserve
   Portion of Total Related to
MGP Investigation and
Remediation
 

December 31, 2015

  Total Environmental
Investigation and
Remediation Reserve
   Portion of Total Related to
MGP Investigation and
Remediation(a)
 

Exelon

  $347    $277    $369    $301  

Generation

   63          63       

ComEd

   238     235     266     264  

PECO

   45     42     37     35  

BGE

   1          3     2  

PHI (Predecessor)

   33     1  

Pepco

   24       

DPL

   3     1  

ACE

   1       

(a)

For BGE, includes reserve for Riverside, a gas purification site. See discussion below for additional information.

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

During the third quarter of 2015, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. For ComEd, the results of the study resulted in a $50 million increase to ComEd’s environmental liabilities and related regulatory assets. The increase at ComEd was primarily driven by refined assumptions and scopes based on further experience and analysis, including one site where a new option is being considered for a facility under which contamination exists and certain sites where another PRP leads the remediation efforts and ComEd shares responsibility. For PECO, the results of the study resulted in a $1 million decrease to PECO’s environmental liabilities and related regulatory assets.

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

Water Quality

Groundwater Contamination.    In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

fly ash, abyproduct generated by coal-fired plants. The consent decree required the payment of a $1 millionpenalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Generation’s remaining groundwater contamination reserve was $12$11 million at September 30, 2015March 31, 2016 and $13$12 million at December 31, 2014.2015.

Air QualityBenning Road Site NPDES Permit Limit Exceedances

Notices.    Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and Findinghas been demolished. The 2009 permit for the first time imposed numerical limits on the allowable concentration of Violations and Midwest Generation Bankruptcy.    Incertain metals in storm water discharged from the site into the Anacostia River as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under2012, Pepco completed the termsimplementation of the sale agreement, Midwest Generationfirst two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, usepainting exposed metal pipes, and operationcovering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the stations, including responsibilitynumerical limits for compliance bymetals. Most of the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising outquarterly monitoring results since the issuance of the environmental liabilities assumed by Midwest Generation and EME under the termspermit have shown exceedances of the agreement governing the sale. In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rightslimits for copper and obligations with respect to its former generation business, including its rightszinc, as well as occasional exceedances for iron and obligations under the sale agreement with Midwest Generation and EME.lead.

Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement.

On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code.

In 2012, the Bankruptcy Court approved the rejection of an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations thereunder. A settlement was reached in January 2015, to resolve the claims related to the coal rail car lease for approximately $14 million and Exelon recorded a gain upon receipt of the funds, within Operating and maintenance expense in Exelon and Generation’s Consolidated Statement of Operations and Comprehensive Income. No further action is expected related to the rail car lease.

On March 11, 2014, the Bankruptcy Court for the Northern District of Illinois entered its Order Confirming Debtors’ Joint Chapter 11 Plan of Reorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME’s portfolio of generation, including Midwest Generation and the Joint Chapter 11 Plan of Reorganization (Plan) became effective. As part of the Plan, the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement were rejected.

Generation increased its reserve for asbestos-related bodily injury claims pertaining to Midwest Generations’ share of liability as a result of the rejection of the asbestos cost sharing agreement in the bankruptcy proceedings. Exelon and Generation may be entitled to damages associated with the rejection of the agreement and a claim has been filed by Exelon for such damages. These amounts are considered to be contingent gains and would not be recognized until realized.

As a prior owner of the generating stations, ComEd (and Generation, through its agreement in Exelon’s 2001 corporate restructuring to assume ComEd’s rights and obligations associated with its former generation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

business) could face liability (along with any other potentially responsible parties) for environmental conditions atThe NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the stations requiring remediation,permit until the Benning Road site has come into compliance with the determinationexisting permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the allocation amongthird phase of BMPs. As of that date, Pepco had fully implemented most of the partieselements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. However, more recent sampling results continued to show modest exceedances for copper and zinc. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to many uncertain factors. ComEdvariation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and Generation are unable to predict whetherhas begun the process of evaluating treatment options. The nature and to what extent they may ultimatelyscope of the necessary treatment system, and the amount of the associated capital expenditures, will not be held responsible for remediationknown until Pepco has completed the evaluation and other costs relating to the generating stations and as a result no liabilitydesign process.

Pepco has been recordedengaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. While the amount of September 30, 2015. Any liability imposed on ComEd or Generation for environmental matters relatingcivil penalties is not known at this time, and Pepco does not expect the amount of such penalties to the generating stations could have a material adverse impacteffect on their futureExelon’s, PHI’s and Pepco’s consolidated financial condition, results of operations or cash flows, Pepco has established what it believes is an appropriate reserve for this matter.

Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree before the end of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to May 16, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

On March 14, 2016, the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. As an intervenor, the Anacostia Riverkeeper will be entitled to file a brief commenting on the proposed consent decree and to appeal any decision by the court to approve the consent decree over the Anacostia Riverkeeper’s objection, but its participation is not expected to materially affect the progress or outcome of the consent decree negotiations.

Potomac River Mineral Oil Release.    In January 2011, there was a release of 4,500 gallons of non-toxic mineral oil at Pepco’s Potomac River substation in Alexandria, Virginia into the Potomac River.

In March 2014, Pepco and the District of Columbia Department of Energy and Environment (DOEE) (formerly The District of Columbia Department of the Environment) entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, Exelon, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

Solid and Hazardous Waste

Cotter Corporation.    The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third- party.third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the U.S. EPA for review. Since June 2012, the U.S. EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study, that are now scheduled to be conducted through 2016. In light of these additional requests, it is unknown whencompleted in mid-2016 to enable the U.S EPA willto propose a remedy for public comment but will likely be sometime in 2017 atby the earliest.end of 2016. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote. The U.S. EPA is also reviewing a partial excavation remedy; however, until the current

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

sampling is concluded there is no basis to determine the likelihood and estimate of a partial excavation remedy.The current estimated cost of the landfill cover remediation for the site is approximately $60 million, which will be allocated among all PRPs. Recent investigation has identified a number of other parties who may be PRPs andcould be liable to contribute to the final remedy. Further investigation is underway. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability.

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA’s public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows. Finally, one of the other PRP’s, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.

On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). Such legislation would become final upon passage in the U.S. House of Representatives and the signature of the President, and be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but could delay the determination of a final remedy and its implementation.

On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program.FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2016 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

Commencing in February 2012, 41 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, and Cotter, which remains a defendant. The suits allege that individuals

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Commencing in February 2012, 36 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon (subsequently dismissed from the case), Generation and ComEd (the Exelon defendants) and Cotter. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the Exelon defendants’Cotter’s negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. The court has dismissed the lawsuits filed by 30 of the plaintiffs. Pre-trial motions and discovery are proceeding in the remaining cases and a proposed pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.

68th Street Dump.    In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, asettlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in thefirst quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated range of costs noted above. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site.Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site.

Rossville Ash Site.    The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $9 million which has been fully reserved as of September 30, 2015.March 31, 2016.

Sauer Dump.    On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP’s signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP’s to conduct a Remedial Investigationremedial investigation (RI) and Feasibility Studyfeasibility study (FS) at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s reasonably possible loss, if any, cannot be determined.

RiversideRiverside..    In 2013, the Maryland Department of the Environment (MDE),MDE, at the request of U.S. EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requestedthat BGE conduct an investigation of three specific areas of the site, and a site-wide investigation of soils,

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time. Upon completion of the investigation the MDE will determine if the site requires further action and/or remediation. Based upon the investigation to date, BGE has established what it believes is an appropriate reserve. As theinvestigation and potential remediation proceed, it is possible that additional reserves could be established, in amounts that could be material to BGE.

Benning Road Site.    In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generatingfacility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons.In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial RI field work began in January 2013 and was completed in December 2014. In addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the second quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review on February 29, 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed with an FS to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS evaluation has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report to DOEE.

Upon DOEE’s approval of the final remedial investigation and feasibility study Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions based on the results of the remedial investigation and feasibility study. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

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(Dollars in millions, except per share data, unless otherwise noted)

DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016. PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and have estimated that the costs of remediation are in the range of approximately $9 million to $13 million. An estimated liability for this issue has been accrued.

Anacostia River Tidal Reach.     Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, DOEE has been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. On March 18, 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE has asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning site resulting from the Benning RI/FS. Pepco will review the draft river-wide RI report and consider its response to this request during the second quarter of 2016. At this time, it is not possible to predict the nature or extent of Pepco’s possible participation in the river-wide RI/FS process, or its potential exposure for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative.

Conectiv Energy Wholesale Power Generation Sites.    In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the 9 generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and PHI has established an appropriate accrual for its share of the estimated clean-up costs.

In September 2011, PHI received a request for data from the EPA regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, Exelon and PHI do not expect this inquiry to have a material adverse effect on their consolidated financial condition, results of operations or cash flows.

Rock Creek Mineral Oil Release.    In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. Exelon, PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

Peck Iron and Metal Site.    EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation on its belief that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a RI/FS for the site using Federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

Brandywine Fly Ash Disposal Site.    In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

Litigation and Regulatory Matters

Except to the extent noted below, the circumstances set forth in Note 22 of the Exelon 2014 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

Asbestos Personal Injury Claims (Exelon, Generation, ComEd, PECO and BGE)

Exelon and Generation.    Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.

At September 30, 2015March 31, 2016 and December 31, 2014,2015, Generation had reserved approximately $95$93 million and $100$95 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2015,March 31, 2016, approximately $20 $21

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

million of this amount related to 217234 open claims presented to Generation, while the remaining $75$72 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300two weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court’s ruling in November 2013, , Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved againstfor on a claim by claim basis. Those additional claims are taken into account in projecting estimatedestimates of future asbestos-related bodily injury claims.

On June 27, 2014,November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois’ Workers’ Compensation Act and the Workers’ Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court’s ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker’s Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker’s Compensation claim. This decision is now on appeal to the Illinois Supreme Court. If confirmed on

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

appeal, former employees could file suit against Exelon, Generation, and ComEd similar to the way former employees are filing suit against Exelon in Pennsylvania. Currently, Exelon, Generation, and ComEd are unable to predict whether and to what extent they may experience additional claims in the future as a result of this ruling; as such, nohave not recorded an increase to the asbestos-related bodily injury liability has been recorded as of September 30, 2015.March 31, 2016.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon’s, Generation’s, PECO’sBGE’s, and ComEd’sPECO’s future results of operations and cash flows.

BGE.    Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

Approximately 468452 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

Discovery begins in these cases after they are placed on the trial docket. At present, only two of the pending cases are set for trial. Given the limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:

 

the identity of the facilities at which the plaintiffs allegedly worked as contractors;

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

the names of the plaintiffs’ employers;

 

the dates on which and the places where the exposure allegedly occurred; and

 

the facts and circumstances relating to the alleged exposure.

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

Continuous Power Interruption (ComEd)(Exelon and ComEd)

Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law.

On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd’s service territory, as well as for five other storm systems that affected ComEd’s customers during June As of March 31, 2016 and July 2011 (Summer 2011 Storm Docket). In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket).

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

On June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. The ICC held that for the July 11, 2011 storm, 34,559 interruptions were preventable and therefore no waiver should apply. As required by the ICC’s Order, ComEd notified relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. On JulyDecember 31, 2014, the Illinois Appellate Court reaffirmed the ICC’s decision in ComEd’s appeal of the Summer 2011 Storm Docket and dismissed ComEd’s appeal of the February 2011 Blizzard Docket. The Illinois Supreme Court denied ComEd’s request to hear the matter. The ICC’s order is now final and claims from impacted customers and municipalities are now eligible for review and reimbursement. ComEd is processing claims received to date.

In the second quarter of 2013, ComEd established a liability, which is not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC’s June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd’s ultimate liability will be based on actual claims eligible for reimbursement. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd’s results of operations or cash flows.

ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows.

Telephone Consumer Protection Act Lawsuit (ComEd)

On November 19, 2013, a class action complaint was filed in the Northern District of Illinois on behalf of a single individual and a presumptive class that would include all customers that ComEd enrolled in its Outage Alert text message program. The complaint alleges that ComEd violated the Telephone Consumer Protection Act (TCPA) by sending approximately 1.2 million text messages to customers without first obtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys’ fees, and an order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $500 to $1,500 per text. In February 2014, ComEd filed a motion to dismiss this class action complaint, which was denied in June 2014. On February 19, 2015, ComEd and the plaintiff agreed in principle to settle the suitdid not have any material liabilities recorded for $5 million, which ComEd has recorded as a liability as of September 30, 2015. On September 11, 2015, the court granted final approval of the settlement. ComEd deposited funds for the settlement directly into an escrow account in September 2015, with payments to the class expected to commence in the fourth quarter 2015.these storm events.

Baltimore City Franchise Taxes (BGE)(Exelon and BGE)

The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City’s claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

General (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

See Note 1215 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

20.19.     Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2015March 31, 2016 and 2014:2015:

 

Three Months Ended September 30, 2015

  Exelon Generation ComEd   PECO BGE 
                 Successor  Predecessor 
 Three Months Ended March 31, 2016 March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
 
 Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHI 

Other, Net

                  

Decommissioning-related activities:

                  

Net realized income on decommissioning trust funds(a)

                  

Regulatory agreement units

  $39   $39   $    $   $   $34   $34   $   $   $   $   $   $   $   $  

Non-regulatory agreement units

   18    18                 21    21                                  

Net unrealized losses on decommissioning trust funds

       

Net unrealized gains on decommissioning trust funds

           

Regulatory agreement units

   (301  (301               79    79                                  

Non-regulatory agreement units

   (218  (218               52    52                                  

Net unrealized gains on pledged assets

           

Zion Station decommissioning

  2    2                                  

Regulatory offset to decommissioning trust fund-related activities(b)

   207    207                 (95  (95                                
  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total decommissioning-related activities

   (255  (255               93    93                                  
  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Investment income (expense)

   4    1         (1  1(c) 

Investment income

  6    1            1(c)                     

Long-term lease income

   4                     4                                      

Interest income related to uncertain income tax positions

  1                    1        1          

AFUDC — Equity

   6        1     1    4    8        2    2    3    4    1    2    1    7  

Loss on debt extinguishment

  (2  (2                                

Other

   (3  (3  3     1    (1  4    1    2            4    2    1    1    (11
  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Other, net

  $(244 $(257 $4    $1   $4   $114   $93   $4   $2   $4   $9   $3   $4   $2   $(4
  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Nine Months Ended September 30, 2015

  Exelon  Generation  ComEd   PECO  BGE 

Other, Net

       

Decommissioning-related activities:

       

Net realized income on decommissioning trust funds(a)

       

Regulatory agreement units

  $203   $203   $    $   $  

Non-regulatory agreement units

   122    122               

Net unrealized losses on decommissioning trust funds

       

Regulatory agreement units

   (385  (385             

Non-regulatory agreement units

   (274  (274             

Net unrealized gains on pledged assets

       

Zion Station decommissioning

   9    9               

Regulatory offset to decommissioning trust fund-related activities(b)

   129    129               
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Total decommissioning-related activities

   (196  (196             
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Investment income (expense)

   6    1         (1  3(c) 

Long-term lease income

   12                   

Interest income related to uncertain income tax positions

       1               

AFUDC — Equity

   16        2     4    10  

Terminated interest rate swaps(d)

   (26                 

Other

   9    1    12           
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Other, net

  $(179 $(193 $14    $3   $13  
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

 

Three Months Ended September 30, 2014

  Exelon  Generation  ComEd   PECO   BGE 

Other, Net

        

Decommissioning-related activities:

        

Net realized income on decommissioning trust funds(a)

        

Regulatory agreement units

  $55   $55   $    $    $  

Non-regulatory agreement units

   39    39                

Net unrealized losses on decommissioning trust funds

        

Regulatory agreement units

   (107  (107              

Non-regulatory agreement units

   (41  (41              

Net unrealized gains on pledged assets

        

Zion Station decommissioning

   7    7                

Regulatory offset to decommissioning trust fund-related activities(b)

   29    29                
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

 

Total decommissioning-related activities

   (18  (18              
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

 

Investment income (expense)

                     1(c) 

Long-term lease income

   4                    

Interest income related to uncertain income tax positions

   25    27       

AFUDC — Equity

   5             2     3  

Other

       (5  4            
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

 

Other, net

  $16   $4   $4    $2    $4  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Nine Months Ended September 30, 2014

  Exelon Generation ComEd   PECO BGE 
  Three Months Ended March 31, 2015 
                Predecessor             
  Exelon Generation ComEd   PECO   BGE PHI   Pepco   DPL   ACE 

Other, Net

                      

Decommissioning-related activities:

                      

Net realized income on decommissioning trust funds(a)

                      

Regulatory agreement units

  $167   $167   $    $   $    $71   $71   $    $    $   $    $    $    $  

Non-regulatory agreement units

   102    102                  29    29                                   

Net unrealized gains on decommissioning trust funds

                      

Regulatory agreement units

   126    126                  48    48                                   

Non-regulatory agreement units

   100    100                  40    40                                   

Net unrealized gains on pledged assets

                      

Zion Station decommissioning

   27    27                  10    10                                   

Regulatory offset to decommissioning trust fund-related
activities
(b)

   (270  (270                (106  (106                                 
  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

   

 

   

 

  

 

   

 

   

 

   

 

 

Total decommissioning-related activities

   252    252                  92    92                                   
  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

   

 

   

 

  

 

   

 

   

 

   

 

 

Investment income (expense)

   1    1         (1  5(c) 

Investment income

   1    1              1(c)                    

Long-term lease income

   20                      4                                       

Interest income related to uncertain income tax positions

   41    53                      1                                   

AFUDC — Equity

   17        3     5    9     5             2     3    4     3          1  

Terminated interest rate swaps(d)

   (23  3                                   

Other

   15        11     1         1    (3  3              5     2     2       
  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

   

 

   

 

  

 

   

 

   

 

   

 

 

Other, net

  $346   $306   $14    $5   $14    $80   $94   $3    $2    $4   $9    $5    $2    $1  
  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

   

 

   

 

  

 

   

 

   

 

   

 

 

 

(a)

Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)

Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 1516 — Asset Retirement Obligations of the Exelon 20142015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)

Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K for additional information regarding the rate stabilization deferral.

(d)

In January 2015, in connection with Generation’s $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments arewere probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCIAOCI to Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following utility taxes are included in revenues and expenses for the three months ended March 31, 2016 and 2015. Generation’s utility tax expense represents gross receipts tax related to its retail operations and the utility registrants’ utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

                                   Successor  Predecessor 
   Three Months Ended March 31, 2016   March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
 
   Exelon   Generation   ComEd   PECO   BGE   Pepco   DPL   ACE   PHI  PHI 

Utility taxes

  $153    $28    $59    $35    $24    $79    $5    $    $7   $77  

   Three Months Ended March 31, 2015 
                       Predecessor             
   Exelon   Generation   ComEd   PECO   BGE   PHI   Pepco   DPL   ACE 

Utility taxes

  $148    $27    $62    $35    $24    $85    $80    $5    $  

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the ninethree months ended September 30, 2015March 31, 2016 and 2014:2015:

 

Nine Months Ended September 30, 2015

  Exelon Generation ComEd   PECO   BGE 
                 Successor  Predecessor 
 Three Months Ended March 31, 2016 March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
 
 Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHI 

Depreciation, amortization, accretion and depletion

                   

Property, plant and equipment

  $1,648   $739   $471    $179    $216   $606   $278   $170   $60   $75   $42   $27   $20   $9   $94  

Regulatory assets

   131        57     19     55  

Amortization of regulatory assets

  65        19    7    34    33    12    20    5    58  

Amortization of intangible assets, net

   39    35                  14    11                                  

Amortization of energy contract assets and liabilities(a)

   (20  (19                (14  (14                                

Nuclear fuel(b)

   841    841                  283    283                                  

ARO accretion(c)

   291    291                  109    109                                  
  

 

  

 

  

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total depreciation, amortization, accretion and depletion

  $2,930   $1,887   $528    $198    $271   $1,063   $667   $189   $67   $109   $75   $39   $40   $14   $152  
  

 

  

 

  

 

   

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Nine Months Ended September 30, 2014

  Exelon   Generation   ComEd   PECO   BGE 
  Three Months Ended March 31, 2015 
                  Predecessor             
  Exelon Generation ComEd   PECO   BGE   PHI   Pepco   DPL   ACE 

Depreciation, amortization, accretion and depletion

                          

Property, plant and equipment

  $1,549    $686    $438    $169    $215    $540   $242   $154    $58    $71    $96    $40    $25    $19  

Regulatory assets

   150          83     7     60  

Amortization of regulatory assets

   58        21     4     35     59     22     14     24  

Amortization of intangible assets, net

   33     33                    12    12                                    

Amortization of energy contract assets and liabilities(a)

   83     93                    (31  (32                                  

Nuclear fuel(b)

   790     790                    272    272                                    

ARO accretion(c)

   251     251                    97    97                                    
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total depreciation, amortization, accretion and depletion

  $2,856    $1,853    $521    $176    $275    $948   $591   $175    $62    $106    $155    $62    $39    $43  
  

 

   

 

   

 

   

 

   

 

   

 

  

 

  

 

   

 

   

 

   

 

   

 

   

 

   

 

 

 

(a)

Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(b)

Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(c)

Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

Nine Months Ended September 30, 2015

  Exelon  Generation  ComEd  PECO  BGE 

Other non-cash operating activities:

    

Pension and non-pension postretirement benefit costs

  $476   $200   $155   $29   $49  

Loss from equity method investments

   3    4              

Provision for uncollectible accounts

   114    15    46    37    15  

Stock-based compensation costs

   102                  

Other decommissioning-related activity(a)

   (31  (31            

Energy-related options(b)

   18    18              

Amortization of rate stabilization deferral

   60                60  

Amortization of debt fair value adjustment

   (34  (9            

Discrete impacts of EIMA(c)

   101        101          

Amortization of debt costs

   43    12    3    2    2  

Increase in inventory reserve

   7    8              

Lower of cost or market inventory adjustment

   15    15              

Other

   (18  (5  7    1    (15
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total other non-cash operating activities

  $856   $227   $312   $69   $111  
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Changes in other assets and liabilities:

    

Under/over-recovered energy and transmission costs

  $47   $   $27   $12   $8  

Other regulatory assets and liabilities

   (12      29    (4  (106

Cash deposits(d)

   (190  (190            

Other current assets

   (132  (143  2    (23)(e)   55  

Other noncurrent assets and liabilities

   (193  (92  (65  (3    
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total changes in other assets and liabilities

  $(480 $(425 $(7 $(18 $(43
  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Non-cash investing and financing activities:

    

Change in PPE related to the ARO update

  $811   $811   $   $   $  

Change in capital expenditures not paid

   59(j)   48(j)   62    (23  (14

Non-cash financing of capital projects

   52    52              

Indemnification of like-kind exchange position(f)

           5          

Long-term software licensing agreement(g)

   95                  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Nine Months Ended September 30, 2014

  Exelon Generation ComEd PECO BGE 
                  Successor  Predecessor 
  Three Months Ended March 31, 2016 March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
 
  Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHI 

Other non-cash operating activities:

                  

Pension and non-pension postretirement benefit costs

  $437   $193   $129   $28   $50    $136   $54   $41   $8   $16   $8   $5   $4   $3   $23  

Equity method investments

   20    20              

Loss from equity method investments

   3    3                                  

Provision for uncollectible accounts

   96    10    9    39    38     41    6    9    16    12    5    5    7    (2  16  

Stock-based compensation costs

   111                     44                                    3  

Other decommissioning-related activity(a)

   (102  (102               (55  (55                                

Energy-related options(b)

   92    92                 (9  (9                                

Amortization of regulatory asset related to debt costs

   8                     1        1            1                1  

Amortization of rate stabilization deferral

   50                50     20                20    1    4            5  

Amortization of debt fair value adjustment

   (45  (17               (3  (3                                

Discrete impacts from EIMA(c)

   (32      (32           (14      (14                            

Amortization of debt costs

   36    9    4    2    2     8    4    1    1    1                      

Merger-related commitments

   44    44              

Provision for excess and obsolete inventory

   1    1                1    1    1        1  

Merger-related commitments(d)(e)

   503    3                138    100    120    358      

Severance costs

   69    4                            52      

Asset retirement costs

                           4    2          

Lower of cost or market inventory adjustment

   36    36                                  

Other

   (17  2    6    1    (11   23    7    (6  (1  (5  (1  (1  (2  (1  (3
  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total other non-cash operating activities

  $698   $251   $116   $70   $129    $804   $51   $32   $24   $44   $153   $118   $132   $410   $46  
  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Changes in other assets and liabilities:

      

Under/over-recovered energy and transmission costs

  $53   $   $63   $(14 $6  

Other regulatory assets and liabilities

   (63      (14  (14  (89

Cash deposits(d)

   (280  (280            

Other current assets

   (78  24    (9  (48)(e)   25  

Other noncurrent assets and liabilities

   (168  (111  22    1    (9
  

 

  

 

  

 

  

 

  

 

 

Total changes in other assets and liabilities

  $(536 $(367 $62   $(75 $(67
  

 

  

 

  

 

  

 

  

 

 

Non-cash investing and financing activities:

                  

Fair value of net assets recorded upon CENG consolidation

  $3,400   $3,400   $   $   $  

Change in PPE related to the ARO update

   (91  (91   

Change in capital expenditures not paid

   (73)(j)   (100)(j)   13    (13  31    $(290 $(234 $25   $(65 $(4 $9   $8   $(9 $(7 $11  

Issuance of equity units(h)

   131                  

Uranium procurement(i)

   70    70              

Indemnification of like-kind exchange position(f)

           4          

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash(d)(f)

       119                                  

Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash(d)(f)

                                   127      

Fair value of pension obligation transferred in connection with the PHI Merger

                                   45      

Assumption of member purchase liability

                                   29      

Change in PPE related to ARO update

   62    62                                  

Indemnification of like-kind exchange position(g)

           1                              

Non-cash financing of capital projects

   31    31                                  

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

   Three Months Ended March 31, 2015 
                   Predecessor             
   Exelon  Generation  ComEd   PECO  BGE  PHI   Pepco   DPL   ACE 

Other non-cash operating activities:

              

Pension and non-pension postretirement benefit costs

  $159   $67   $52    $10   $16   $24    $8    $4    $4  

Provision for uncollectible accounts

   84    4    22     33    25    16     4     7     5  

Stock-based compensation costs

   39                     3                 

Other decommissioning-related activity(a)

   (44  (44                                

Energy-related options(b)

   9    9                                  

Amortization of regulatory asset related to debt costs

   3        2     1        1     1            

Amortization of rate stabilization deferral

   25                 25    11     10     1       

Amortization of debt fair value adjustment

   (9  (4                                

Discrete impacts from EIMA(c)

   46        46                              

Amortization of debt costs

   18    4    1     1    1                     

Lower of cost or market inventory adjustment

   10    10                                  

Other

   4    (1  3     (1  (3  2               (1
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Total other non-cash operating activities

  $344   $45   $126    $44   $64   $57    $23    $12    $8  
  

 

 

  

 

 

  

 

 

   

 

 

  

 

 

  

 

 

   

 

 

   

 

 

   

 

 

 

Non-cash investing and financing activities:

              

Change in PPE related to ARO update

   56    56                                  

Indemnification of like-kind exchange position(g)

           2                              

 

(a)

Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — 16—Asset Retirement Obligations of the Exelon 20142015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(b)

Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)

Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.

(d)

Relates primarilySee Note 4 — Mergers, Acquisitions and Dispositions for additional information related to cash deposits made to ISOs/RTOs.the merger with PHI.

(e)

Relates primarilyExcludes $5 million of forgiveness of Accounts receivable related to prepaid utility taxes.merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.

(f)

Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion such net assets to Generation.

(g)

See Note 12 —11— Income Taxes for discussion of the like-kind exchange tax position.

(g)

Relates to a long-term software license agreement entered into on May 31, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note 11 —Debt and Credit Agreements for additional information.

(h)

Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 17—Common Stock for additional information.

(i)

Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.

(j)

Includes $22 million of changes in capital expenditures not paid between December 31, 2014 and September 30, 2015 and $175 million between December 31, 2013 and September 30, 2014 related to Antelope Valley.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

DOE Smart Grid Investment Grant (Exelon and PECO).    For the nine months ended September 30, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $5 million related to PECO’s DOE SGIG programs. For the nine months ended September 30, 2015 PECO had no capital expenditures or reimbursements, as the DOE SGIG program was completed during 2014. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information regarding the DOE SGIG.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2015March 31, 2016 and December 31, 2014.2015.

 

September 30, 2015

  Exelon Generation ComEd   PECO BGE 
           Successor       

March 31, 2016

 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 

Property, plant and equipment:

                

Accumulated depreciation and amortization

  $16,185(a)  $8,659(a)  $3,614    $3,058   $2,962   $16,776(a)  $8,950(a)  $3,716   $3,139   $3,069   $4   $2,960   $1,140   $983  

Accounts receivable:

                

Allowance for uncollectible accounts

   329(c)   70    100     98(c)   61   $351   $73   $82   $90   $53   $53   $16   $19   $18  

 

December 31, 2014

  Exelon Generation ComEd   PECO BGE 
           Predecessor       

December 31, 2015

 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE 

Property, plant and equipment:

                

Accumulated depreciation and amortization

  $14,742(b)  $7,612(b)  $3,432    $2,917   $2,868   $16,375(b)  $8,639(b)  $3,710   $3,101   $3,016   $5,341   $2,929   $1,139   $968  

Accounts receivable:

                

Allowance for uncollectible accounts

   311(c)   60    84     100(c)   67   $284   $77   $75   $83   $49   $56   $17   $17   $17  

 

(a)

Includes accumulated amortization of nuclear fuel in the reactor core of $3,093$3,008 million.

(b)

Includes accumulated amortization of nuclear fuel in the reactor core of $2,673$2,861 million.

(c)

Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables described below of $9 million and $7 million at September 30, 2015 and December 31, 2014, respectively.

PECO Installment Plan Receivables (Exelon and PECO)

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $14 million and $15 million as of September 30, 2015March 31, 2016 and December 31, 2014 each.2015, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 20142015 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2015March 31, 2016 of $17$13 million consists of $1 million, $4$3 million and $12$9 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 20142015 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2015March 31, 2016 and December 31, 20142015 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 20142015 Form 10-K.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

21.20. Segment Information (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.

In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has ninetwelve reportable segments, which include ComEd, PECO, BGE, PHI’s three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO, BGE, Pepco, DPL and BGEACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and BGE’sACE’s CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and BGEACE based on net income and return on equity.

Effective with the consummation of the PHI Merger, PHI’s reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI’s reportable segments consist of Pepco, DPL and ACE. PHI’s Predecessor periods’ segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI’s reported consolidated revenues or net income. PHI’s CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.

The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:

 

  

Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

 

  

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

 

  

New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

 

  

New York represents operations within ISO-NY, which covers the state of New York in its entirety.

 

  

ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

 

Other Power Regions:

Other Power Regions:

 

  

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

  

West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.

 

  

Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

The CODMs for Exelon and Generation evaluate the performance of Generation’s power marketing activities and allocate resources based on revenue net of purchased power and fuel expense (RNF). Generation

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd, PECO, and BGE.the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation’s other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation’s overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also not included in the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended March 31, 2016 and 2015 is as follows:

Three Months Ended September 30,March 31, 2016 and 2015 and 2014

 

   Generation(a)   ComEd   PECO   BGE   Other(b)  Intersegment
Eliminations
  Exelon 

Total revenues(c):

            

2015

  $4,768    $1,376    $740    $725    $348   $(556 $7,401  

2014

   4,412     1,222     693     697     305    (417  6,912  

Intersegment revenues(d):

            

2015

  $205    $1    $1    $3    $347   $(555 $2  

2014

   112     1          3     302    (418    

Net income (loss):

            

2015

  $332    $149    $90    $54    $(36 $(2 $587  

2014

   849     126     81     49     (31      1,074  

Total assets:

            

September 30, 2015

  $46,479    $26,129    $10,072    $8,134    $16,256   $(11,942 $95,128  

December 31, 2014

   45,348     25,392     9,943     8,078     9,794    (11,741  86,814  
                   Successor          
   Generation(a)   ComEd   PECO   BGE   PHI(b)  Other(c)  Intersegment
Eliminations
  Exelon 

Operating revenues(d):

             

2016

             

Competitive businesses electric revenues

  $3,695    $    $    $    $   $   $(266 $3,429  

Competitive businesses natural gas revenues

   822                                822  

Competitive businesses other revenues

   222                                222  

Rate-regulated electric revenues

        1,249     644     680     90        (6  2,657  

Rate-regulated natural gas revenues

             197     249     3        (5  444  

Shared service and other revenues

                       12    405    (418  (1

2015

             

Competitive businesses electric revenues

  $4,397    $    $    $    $   $   $(209 $4,188  

Competitive businesses natural gas revenues

   1,124                                1,124  

Competitive businesses other revenues

   319                            (1  318  

Rate-regulated electric revenues

        1,185     677     713             (1  2,574  

Rate-regulated natural gas revenues

             308     323             (7  624  

Shared service and other revenues

                           318    (316  2  

Intersegment revenues(e):

             

2016

  $266    $5    $1    $5    $12   $405   $(695 $(1

2015

   210     1          7         317    (533  2  

Net income (loss):

             

2016

  $257    $115    $124    $101    $(309 $(164 $(1 $123  

2015

   485     90     139     109         (84  (1  738  

Total assets:

             

March 31, 2016

  $47,002    $26,887    $10,462    $8,361    $20,932   $9,751   $(11,653 $111,742  

December 31, 2015

   46,529     26,532     10,367     8,295         15,389    (11,728  95,384  

 

(a)

Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2015March 31, 2016 include revenue from sales to PECO of $61$79 million and sales to BGE of $141$173 million in the Mid-Atlantic region, and sales to ComEd of $2$5 million in the Midwest.Midwest region. For the three months ended September 30, 2014,March 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $28$63 million and sales to BGE of $83$138 million in the Mid-Atlantic region, and sales to ComEd of $1$9 million in the Midwest region.

(b)

Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c)

For the three months ended September 30, 2015 and 2014, utility taxesSuccessor period of $28March 24, 2016 to March 31, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $6 million, sales to DPL of $4 million, and $22sales to ACE of $1 million respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2015 and 2014, utility taxes of $63 million and $61 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2015 and 2014, utility taxes of $37 million and $34 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2015 and 2014, utility taxes of $23 million and $21 million, respectively, are included in revenues and expenses for BGE.Mid-Atlantic region.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

(b)

Amounts included represent activity for the PHI’s successor period, March 24, 2016 through March 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI’s predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the three months ended March 31, 2015.

(c)

Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.

(d)

Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2016 and 2015.

(e)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Generation total revenues:

 

  Three Months Ended September 30, 2015   Three Months Ended September 30, 2014   Three Months Ended March 31, 2016   Three Months Ended March 31, 2015 
  Revenues
from  External
Customers(a)
   Intersegment
Revenues
 Total
Revenues
   Revenues
from  External
Customers(a)
   Intersegment
Revenues
 Total
Revenues
   Revenues
from external
customers(a)
   Intersegment
revenues
 Total
Revenues
   Revenues
from external
customers(a)(c)
   Intersegment
revenues(c)
 Total
Revenues(c)
 

Mid-Atlantic

  $1,622    $10   $1,632    $1,285    $4   $1,289    $1,532    $(12 $1,520    $1,556    $(43 $1,513  

Midwest

   1,150     1    1,151     1,062     (1  1,061     1,089     6    1,095     1,276         1,276  

New England

   519     1    520     272         272     471     (1  470     865     (6  859  

New York

   254     (4  250     230     2    232     218     (15  203     307     3    310  

ERCOT

   317     (1  316     303     (1  302     163         163     181     (1  180  

Other Power Regions(b)

   383     (7  376     381     (6  375     222     1    223     212     2    214  
  

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

 

Total Revenues for Reportable Segments

   4,245         4,245     3,533     (2  3,531     3,695     (21  3,674     4,397     (45  4,352  
  

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

 

Other(c)(b)

   523         523     879     2    881     1,044     21    1,065     1,443     45    1,488  
  

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

 

Total Generation Consolidated Operating Revenues

  $4,768    $   $4,768    $4,412    $   $4,412    $4,739    $   $4,739    $5,840    $   $5,840  
  

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

   

 

   

 

  

 

 

 

(a)

Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.the Utility Registrants.

(b)

Other Power Regions includes the South, West and Canada.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $3$20 million decrease to revenues and a $22$40 million decreaseincrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, unrealized mark-to-market lossesgains of $7$63 million and gains of $271$154 million for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, and the elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense:

   Three Months Ended September 30, 2015   Three Months Ended September 30, 2014 
   RNF
from  External
Customers(a)
  Intersegment
RNF
  Total
RNF
   RNF
from  External
Customers(a)
   Intersegment
RNF
  Total
RNF
 

Mid-Atlantic

  $974   $17   $991    $921    $14   $935  

Midwest

   752        752     722     (6  716  

New England

   145    (12  133     120     (30  90  

New York

   159    8    167     176     10    186  

ERCOT

   166    (55  111     186     (77  109  

Other Power Regions(b)

   167    (84  83     157     (89  68  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Total Revenues net of purchased power and fuel for Reportable Segments

   2,363    (126  2,237     2,282     (178  2,104  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Other(c)

   (114  126    12     250     178    428  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Total Generation Revenues net of purchased power and fuel expense

  $2,249   $   $2,249    $2,532    $   $2,532  
  

 

 

  

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 
(c)

Exelon corrected an error in the March 31, 2015 balances within Intersegment Revenue and Revenue from external customers for an overstatement of $43 million of Intersegment Revenue for Reportable Segments for the three months ended March 31, 2015, an understatement of Revenue from external customers for Reportable Segments of $43 million for the three months ended March 31, 2015, an understatement of $43 million of Intersegment Revenue for Other for the three months ended March 31, 2015, and an overstatement of Revenue from external customers for Other of $43 million for the three months ended March 31, 2015. This error is not considered material to any prior period, and there is no impact to Total Revenues.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

Generation total revenues net of purchased power and fuel expense:

   Three Months Ended March 31, 2016   Three Months Ended March 31, 2015 
   RNF
from external
customers(a)
   Intersegment
RNF
  Total
RNF
   RNF
from  external
customers(a)(c)
   Intersegment
RNF(c)
  Total
RNF(c)
 

Mid-Atlantic

  $832    $9   $841    $808    $(21 $787  

Midwest

   715     3    718     709     (6  703  

New England

   86     (5  81     182     (24  158  

New York

   141     (11  130     169     20    189  

ERCOT

   81     (20  61     88     (33  55  

Other Power Regions

   86     (10  76     72     (26  46  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Total Revenues net of purchased power and fuel expense for Reportable Segments

   1,941     (34  1,907     2,028     (90  1,938  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Other(b)

   356     34    390     379     90    469  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Total Generation Revenues net of purchased power and fuel expense

  $2,297    $   $2,297    $2,407    $   $2,407  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

 

(a)

Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.the Utility Registrants.

(b)

Other Power Regions includes the South, West and Canada.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $4$19 million decrease to RNF and a $15$38 million increase to RNF for the amortization of intangible assets related to commodity contracts for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, unrealized mark-to-market lossesgains of $139$103 million and gains of $267$162 million for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, and the elimination of intersegment revenues.

Nine Months Ended September 30, 2015 and 2014

   Generation(a)   ComEd   PECO   BGE   Other(b)  Intersegment
Eliminations
  Exelon 

Total revenues(c):

            

2015

  $14,841    $3,709    $2,386    $2,388    $1,007   $(1,585 $22,746  

2014

   12,591     3,484     2,343     2,404     924    (1,573  20,173  

Intersegment revenues(d):

            

2015

  $567    $3    $1    $10    $1,003   $(1,581 $3  

2014

   630     2     1     21     920    (1,574    

Net income (loss):

            

2015

  $1,208    $339    $299    $212    $(96 $(3 $1,959  

2014

   1,037     335     255     156     (58      1,725  

(a)

Generation includes the sixrevenue net of purchased power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2015 include revenue from sales to PECO of $173 million and sales to BGE of $376 million in the Mid-Atlantic region, and sales to ComEd of $17 million in the Midwest. For the nine months ended September 30, 2014, intersegment revenues for Generation include revenue from sales to PECO of $165 million and sales to BGE of $290 million in the Mid-Atlantic region, and sales to ComEd of $175 million in the Midwest region.

(b)

Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.fuel expense.

(c)

ForExelon corrected an error in the nineMarch 31, 2015 balances within Intersegment RNF and RNF from external customers for an understatement of $4 million of Intersegment RNF for Reportable Segments for the three months ended September 30,March 31, 2015, an understatement of RNF from external customers for Reportable Segments of $5 million for the three months ended March 31, 2015, an overstatement of $4 million of Intersegment RNF for Other for the three months ended March 31, 2015, and 2014, utility taxesan overstatement of $79RNF from external customers for Other of $5 million and $67 million, respectively, are included in revenues and expenses for Generation. For the ninethree months ended September 30, 2015March 31, 2015. This also included an understatement of total RNF for Reportable Segments and 2014, utility taxesan overstatement of $180total RNF for Other of $9 million and $180 million, respectively, are included in revenues and expenses for ComEd. For the ninethree months ended September 30, 2015March 31, 2015. The error is not considered material to any prior period, and 2014, utility taxes of $104 million and $99 million, respectively, are included in revenues and expensesthere is no net impact to Generation Total RNF for PECO. For the nine months ended September 30, 2015 and 2014, utility taxes of $67 million and $64 million, respectively, are included in revenues and expenses for BGE.2015.

(d)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Generation total revenues:

   Nine Months Ended September 30, 2015   Nine Months Ended September 30, 2014 
   Revenues
from External
Customers(b)
   Intersegment
Revenues
  Total
Revenues
   Revenues
from External
Customers(b)
   Intersegment
Revenues
  Total
Revenues
 

Mid-Atlantic(a)

  $4,475    $16   $4,491    $3,998    $(14 $3,984  

Midwest

   3,630     3    3,633     3,302     11    3,313  

New England

   1,743     3    1,746     1,028     5    1,033  

New York(a)

   786     (8  778     614     (1  613  

ERCOT

   691     (4  687     743     (2  741  

Other Power Regions(c)

   891     (11  880     1,027     (4  1,023  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

 

   Nine Months Ended September 30, 2015   Nine Months Ended September 30, 2014 
   Revenues
from External
Customers(b)
   Intersegment
Revenues
  Total
Revenues
   Revenues
from External
Customers(b)
   Intersegment
Revenues
  Total
Revenues
 

Total Revenues for Reportable Segments

   12,216     (1  12,215     10,712     (5  10,707  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Other(d)

   2,625     1    2,626     1,879     5    1,884  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Total Generation Consolidated Operating Revenues

  $14,841    $   $14,841    $12,591    $   $12,591  
  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

  

 

 

 

Successor and Predecessor PHI:

   Pepco  DPL  ACE  Other(b)  Intersegment
Eliminations
  PHI 

Operating revenues(a):

       

March 24, 2016 to March 31, 2016 — Successor

       

Rate-regulated electric revenues

  $40   $24   $23   $3   $   $90  

Rate-regulated natural gas revenues

       3                3  

Shared service and other revenues

               12        12  

January 1, 2016 to March 23, 2016 —Predecessor

       

Rate-regulated electric revenues

  $511   $279   $268   $42   $(4 $1,096  

Rate-regulated natural gas revenues

       56        1        57  

Shared service and other revenues

                         

Three months ended — March 31, 2015 — Predecessor

       

Rate-regulated electric revenues

  $545   $335   $334   $58   $(4 $1,268  

Rate-regulated natural gas revenues

       86                86  

Shared service and other revenues

                         

Intersegment revenues:

       

March 24, 2016 to March 31, 2016 — Successor

  $   $   $   $12   $   $12  

January 1, 2016 to March 23, 2016 — Predecessor

   1    2    1        (4    

Three months ended — March 31, 2015 — Predecessor

   1    2    1        (4    

Net income (loss):

       

March 24, 2016 to March 31, 2016 — Successor

  $(140 $(98 $(105 $22   $12   $(309

January 1, 2016 to March 23, 2016 — Predecessor

   32    26    5    (44      19  

Three months ended — March 31, 2015 — Predecessor

   26    32    9    (14      53  

Total assets:

       

March 31, 2016 — Successor

  $6,877   $3,959   $3,393   $11,077   $(4,374 $20,932  

December 31, 2015 — Predecessor

   6,908    3,969    3,387    7,158    (5,238  16,184  

 

(a)

On April 1, 2014, Generation assumed operational controlIncludes gross utility tax receipts from customers. The offsetting remittance of CENG’s nuclear fleet. As a result, beginningutility taxes to the governing bodies is recorded in expenses on April 1, 2014, CENG’s revenues are included on a fully consolidated basis.the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2016 and 2015.

(b)

Includes all wholesaleOther primarily includes PHI’s corporate operations, shared service entities and retail electric sales to third partiesother financing and affiliated sales to ComEd, PECO and BGE.

(c)

investment activities. For the predecessor periods presented, Other Power Regions includes the South, Westactivity of PHI’s unregulated businesses which were distributed to Exelon and Canada.

(d)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $19 million increase to revenues and a $203 million decrease to revenues for the amortization of intangible assets related to commodity contracts for the nine months ended September 30, 2015 and 2014, respectively, unrealized mark-to-market gains of $171 million and losses of $572 million for the nine months ended September 30, 2015 and 2014, respectively, and elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense:

   Nine Months Ended September 30, 2015   Nine Months Ended September 30, 2014 
   RNF
from External
Customers(b)
   Intersegment
RNF
  Total
RNF
   RNF
from External
Customers(b)
  Intersegment
RNF
  Total
RNF
 

Mid-Atlantic(a)

  $2,633    $30   $2,663    $2,610   $(60 $2,550  

Midwest

   2,198     (3  2,195     1,856    21    1,877  

New England

   416     (37  379     362    (72  290  

New York(a)

   471     27    498     289    24    313  

ERCOT

   344     (109  235     457    (207  250  

Other Power Regions(c)

   403     (210  193     465    (216  249  
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total Revenues net of purchased power and fuel expense for Reportable Segments

   6,465     (302  6,163     6,039    (510  5,529  
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Other(d)

   576     302    878     (519  510    (9
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

Total Generation Revenues net of purchased power and fuel expense

  $7,041    $   $7,041    $5,520   $   $5,520  
  

 

 

   

 

 

  

 

 

   

 

 

  

 

 

  

 

 

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. Asas a result starting on April 1, 2014, CENG’s revenue net of purchased power and fuel expense are included on a fully consolidated basis.

(b)

Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(c)

Other Power Regions includes the South, West and Canada.

(d)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $20 million increase to RNF and a $78 million decrease to RNF for the amortization of intangible assets related to commodity contracts for the nine months ended September 30, 2015 and 2014, respectively, unrealized mark-to-market gains of $258 million and losses of $477 million for the nine months ended September 30, 2015 and 2014, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.PHI Merger.

Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

(Dollars in millions except per share data, unless otherwise noted)

Exelon Corporation

General

Exelon, a utility services holding company, operates through the following principal subsidiaries:

 

  

Generation,    whose integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services, and engages in natural gas and oil exploration and production activities (Upstream).

 

As a result of the Constellation merger, Generation owns a 50.01% interest in CENG. During 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation fully consolidated CENG’s financial position and results of operations into their financial statements since April 1, 2014.

  

ComEd,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.

 

  

PECO,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

 

  

BGE,    whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and natural gas distribution services in central Maryland, including the City of Baltimore.

Pepco,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland.

DPL,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

ACE,    whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.

Exelon has ninetwelve reportable segments consisting of Generation’s six power marketing reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation), ComEd, PECO, BGE and BGE.PHI’s three utility reportable segments (Pepco, DPL and ACE). See Note 21 — 20—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable segments.

Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.

Exelon’s consolidated financial information includes the results of its foureight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and BGE,ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and BGE.ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Executive Overview

Financial Results.    The following table sets forth the consolidated financial results reflect the results of Exelon for the three and nine months ended September 30, 2015March 31, 2016 compared to the same period in 2014.2015. The 2016 financial results only include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through March 31, 2016. All amounts presented below are before the impact of income taxes, except as noted.

 

  Three Months Ended September 30,  Favorable
(Unfavorable)
Variance
 
  2015  2014  
  Generation(a)  ComEd(c)  PECO(c)  BGE(c)  Other  Exelon(a)  Exelon  

Operating revenues

 $4,768   $1,376   $740   $725   $(208 $7,401   $6,912   $489  

Purchased power and fuel

  2,519    390    278    311    (207  3,291    2,648    (643
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Revenue net of purchased power and fuel(b)

  2,249    986    462    414    (1  4,110    4,264    (154
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Other operating expenses

        

Operating and maintenance

  1,241    404    196    169    (14  1,996    1,982    (14

Depreciation and amortization

  264    176    68    79    19    606    577    (29

Taxes other than income

  123    79    44    57    7    310    306    (4
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total other operating expenses

  1,628    659    308    305    12    2,912    2,865    (47

Equity in earnings of unconsolidated affiliates

                          1    (1

Gain on sales of assets

  1            1        2    338    (336
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Operating income (loss)

  622    327    154    110    (13  1,200    1,738    (538
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Other income and (deductions)

        

Interest expense, net

  (68  (83  (28  (25  (49  (253  (258  5  

Other, net

  (257  4    1    4    4    (244  16    (260
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Total other income and (deductions)

  (325  (79  (27  (21  (45  (497  (242  (255
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Income before income taxes

  297    248    127    89    (58  703    1,496    (793

Income taxes

  (36  99    37    35    (20  115    422    307  

Equity in losses of unconsolidated affiliates

  (1                  (1      (1
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income (loss)

  332    149    90    54    (38  587    1,074    (487

Net income (loss) attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends

  (45          3        (42  81    123  
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

Net income (loss) attributable to common shareholders

 $377   $149   $90   $51   $(38 $629   $993   $(364
 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

 

 Nine Months Ended September 30, Favorable
(Unfavorable)
Variance
  Three Months Ended March 31, Favorable
(Unfavorable)
Variance
 
 2015 2014  2016 2015 
 Generation(a) ComEd(c) PECO(c) BGE(c) Other Exelon(a) Exelon  Generation ComEd PECO BGE PHI(b) Other Exelon Exelon 

Operating revenues

 $14,841   $3,709   $2,386   $2,388   $(578 $22,746   $20,173   $2,573   $4,739   $1,249   $841   $929   $105   $(290 $7,573   $8,830   $(1,257

Purchased power and fuel

  7,800    991    953    1,037    (571  10,210    9,399    (811  2,442    348    321    373    38    (268  3,254    4,470    1,216  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Revenue net of purchased power and fuel(b)(a)

  7,041    2,718    1,433    1,351    (7  12,536    10,774    1,762    2,297    901    520    556    67    (22  4,319    4,360    (41
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Other operating expenses

                 

Operating and maintenance

  3,860    1,166    609    499    (15  6,119    6,005    (114  1,467    368    215    202    449    134    2,835    2,081    (754

Depreciation and amortization

  774    528    198    271    47    1,818    1,732    (86  289    189    67    109    14    17    685    610    (75

Taxes other than income

  369    225    125    169    20    908    887    (21  126    75    42    58    15    9    325    304    (21
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total other operating expenses

  5,003    1,919    932    939    52    8,845    8,624    (221  1,882    632    324    369    478    160    3,845    2,995    (850

Equity in losses of unconsolidated affiliates

                          (20  20  

Gain on sales of assets

  7        1    1    1    10    356    (346      5                4    9    1    8  

Gain on consolidation and acquisition of businesses

                          261    (261
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Operating income (loss)

  2,045    799    502    413    (58  3,701    2,747    954    415    274    196    187    (411  (178  483    1,366    (883
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Other income and (deductions)

                 

Interest expense, net

  (269  (248  (84  (73  (81  (755  (722  (33  (97  (86  (31  (24  (6  (43  (287  (345  58  

Other, net

  (193  14    3    13    (16  (179  346    (525  93    4    2    4    2    9    114    80    34  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total other income and (deductions)

  (462  (234  (81  (60  (97  (934  (376  (558  (4  (82  (29  (20  (4  (34  (173  (265  92  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Income (loss) before income taxes

  1,583    565    421    353    (155  2,767    2,371    396    411    192    167    167    (415  (212  310    1,101    (791

Income taxes

  371    226    122    141    (55  805    646    (159  151    77    43    66    (106  (47  184    363    179  

Equity in earnings (loss) of unconsolidated affiliates

  (4              1    (3      (3

Equity in losses of unconsolidated affiliates

  (3                      (3      3  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Net income (loss)

  1,208    339    299    212    (99  1,959    1,725    234    257    115    124    101    (309  (165  123    738    (615

Net income attributable to noncontrolling interests, preferred security dividends and redemption and preference stock dividends

  (10          10            121    121  

Net (loss) income attributable to noncontrolling interests and preference stock dividends

  (53          3            (50  45    95  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Net income (loss) attributable to common shareholders

 $1,218   $339   $299   $202   $(99 $1,959   $1,604   $355   $310   $115   $124   $98   $(309 $(165 $173   $693   $(520
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 financial results include CENG’s results of operations on a fully consolidated basis.

(b)

The Registrants’Registrants evaluate operating performance using the measure of revenue net of purchased power and fuel expense. The Registrants’Registrants believe that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate itstheir operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

(c)(b)

For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEdAs a result of the PHI Merger, PHI includes the consolidated results of PHI, Pepco, DPL and BGE’s transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).ACE from March 24, 2016, through March 31, 2016.

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    Exelon’s net income attributable to common shareholders was $629$173 million for the three months ended September 30, 2015 as comparedMarch 31, 2016 ascompared to $993$693 million for the three months ended September 30, 2014,March 31, 2015, and diluted earnings per average common share were $0.69$0.19 for the three months ended September 30, 2015March 31, 2016 as compared to $1.15$0.80 for the three months ended September 30, 2014.March 31, 2015.

Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $154$41 million for the three months ended September 30, 2015March 31, 2016 as compared to the same period in 2014.2015. The quarter-over-quarteryear-over-year decrease in operating revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:

 

Decrease of $406$31 million at Generation primarily due to lower realized energy prices and higher oil inventory write downs in 2016 versus 2015, partially offset by nuclear refueling outage timing, fewer non-refueling outage days and increased capacity prices;

Decrease of $59 million at Generation due to mark-to-market lossesgains of $139$103 million in 20152016 from economic hedging activities as compared to $267gains of $162 million in mark-to-market gains in 2014;2015;

 

Decrease of $19 million at Generation related to amortization of energy contracts recorded at fair value duringassociated with prior acquisitions; and

Decrease of $27 million at PECO primarily due to less favorable weather conditions, partially offset by increased electric distribution rate revenue pursuant to the 2015 PAPUC authorized rate increase effective January 1, 2016.

The quarter-over-quarteryear over year decrease in operating revenue net of purchased power and fuel expense was partially offset by the following favorable factors:

 

Increase of $142 million at Generation primarily due the benefit of lower cost to serve load, the inclusion of Integrys’ results in 2015, and increased load served; partially offset by lower margins and capacity revenues resulting from the absence of generating assets sold in 2014;

Increase of $90$43 million at ComEd primarily due to increased electric distribution and transmission formula rate revenue resulting from increased capital investments and an increase in fully recoverable costs and favorable weather, partially offset by lower electric distribution ROE due to a decrease in treasury rates;investment;

 

Increase of $24$7 million at PECOBGE primarily due to favorable weather;an increase in transmission revenue resulting from increased capital investment and operating and maintenance expense; and

 

Increase of $14$67 million at BGE primarilyin revenue net of purchased power and fuel due to increased distribution revenue as a resultthe inclusion of PHI results for the December 2014 electric and natural gas distribution rate case order issued by the Maryland PSC and an increase in fully recoverable costs.period of March 24, 2016 to March 31, 2016.

Operating and maintenance expense increased by $14$754 million for the three months ended September 30, 2015March 31, 2016 as compared to the same period in 20142015 primarily due to the following favorableunfavorable factors:

Approval of the merger across all regulatory jurisdictions was conditioned on Exelon and PHI agreeing to certain commitments pursuant to which, upon acquisition close, Exelon recorded $508 million of costs.

 

Increase in Generation’s labor, contractingseverance expense of $52 million and materials costs$17 million related to employee headcount reductions as a result of $45the closing of the PHI acquisition and the cost management program, respectively;

Long-lived asset impairments of Upstream assets at Generation of $119 million; and

 

An increase in pension and non-pension postretirement benefits expense of $19 million as a result the unfavorable impact of lower assumed pension and OPEB discount rates for 2015 and an increase in the life expectancy assumption for plan participants in 2015; and

Increased fully recoverable energy efficiency programstorm costs at ComEdBGE of $21$17 million.

The quarter-over-quarteryear-over-year increase in operating and maintenance expense was partially offset by the following favorable factors:

 

Long-lived asset impairmentsDecrease of $49$7 million due to a reduction in 2014;the number of nuclear refueling outage days at Generation, including Salem; and

 

Merger and integration costsDecrease of $46$18 million in 2015 as compared to $70 millionpension and non-pension post-retirement benefits resulting from the favorable impact of higher pension and OPEB discount rates in 2014.2016.

Depreciation and amortization expense increased by $29$75 million primarily related toas a result of increased depreciation expense for Generation and ComEd for ongoing capital expenditures, across all registrants.and increased nuclear decommissioning amortization at Generation.

Taxes other than income remained relatively flat quarter-over-quarter.

Gain on sales of assets decreasedincreased by $336$21 million primarily due to the gain on sale of Safe Harbor Water Corporation recorded in 2014.increased payroll taxes and sales and use tax.

Interest expense decreased by $5$58 million primarily as a result of the favorable settlementabsence of the forward-starting interest rate swaps in 2015 of an income tax position on Constellation’s pre-acquisition tax returns at Generation, partially offset by higher outstanding debt at Generation and Corporate.2016.

Other, net decreasedincreased by $260$34 million primarily at Generation as a result of the change in realized and unrealized gains and losses on NDT fund investments at Generation.

Equityfunds and the absence of a $26 million loss in losses2015 on the termination of unconsolidated affiliates remained relatively flat quarter-over-quarter.forward-starting interest rate swaps.

Exelon’s effective income tax rates for the three months ended September 30,March 31, 2016 and 2015 were 59.4% and 2014 were 16.4% and 28.2%33.0%, respectively. See Note 1211 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, Exelon recorded an after-tax charge of $90 million during the three months ended March 31, 2016 as a result of assessment and remeasurement of certain federal and state PHI, Pepco, DPL and ACE uncertain tax positions.

For further detail regarding the financial results for the three months ended September 30, 2015, including explanation of the non-GAAP measure of revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    Exelon’s net income attributable to common shareholders was $1,959 million for the nine months ended September 30, 2015 as compared to $1,604 million for the nine months ended September 30, 2014, and diluted earnings per average common share were $2.22 for the nine months ended September 30, 2015 as compared to $1.86 for the nine months ended September 30, 2014.

Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $1,762 million for the nine months ended September 30, 2015 as compared to the same period in 2014. The year-over-year increase in operating revenue net of purchased power and fuel expense was primarily due to the following favorable factors:

Increase of $692 million at Generation primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015, a reduction in the number of nuclear outage days in 2015, the inclusion of Integrys’ results in 2015, the benefit of lower cost to serve load (which includes the absence of higher procurement costs for replacement power due to extreme cold weather in the first quarter of 2014), the cancellation of the DOE spent nuclear fuel disposal fee, increased capacity prices, favorability from portfolio management optimization activities, and increased load served, partially offset by lower margins and capacity revenues resulting from the absence of generating assets sold in 2014, lower realized energy prices and the absence of fuel optimization opportunities realized in 2014 in the South;

Increase of $98 million at Generation related to amortization of contracts recorded at fair value during prior acquisitions;

Increase of $735 million at Generation due to mark-to-market gains of $258 million in 2015 from economic hedging activities as compared to $477 million in mark-to-market losses in 2014;

Increase of $149 million at ComEd primarily due to increased electric distribution and transmission formula rate revenues due to increased capital investments and an increase in fully recoverable costs, partially offset by lower electric distribution ROE due to a decrease in treasury rates;

Increase of $50 million at PECO primarily due to favorable weather and volume; and

Increase of $41 million at BGE primarily due to increased distribution revenue as a result of the December 2014 electric and natural gas distribution rate case order issued by the Maryland PSC.

Operating and maintenance expense increased by $114 million for the nine months ended September 30, 2015 as compared to the same period in 2014 primarily due to the following unfavorable factors:

Increase in Generation’s labor, contracting and materials costs of $202 million primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015;

An increase in the costs associated with number of planned nuclear refueling outage days, including Salem and the CENG plants, at Generation of $8 million.

An increase in pension and non-pension postretirement benefits expense of $26 million as a result the unfavorable impact of lower assumed pension and OPEB discount rates for 2015 and an increase in the life expectancy assumption for plan participants in 2015, partially offset by cost savings from plan design changes for certain OPEB plans effective April 2014 and forward;

Increase in labor, contracting and materials of $38 million at ComEd due to increased contracting costs related to preventative maintenance and other projects; and

Increased fully recoverable costs associated with uncollectible accounts at ComEd of $37 million.

The year-over-year increase in operating and maintenance expense was partially offset by the following favorable factors:

Long-lived asset impairments of $24 million in 2015 compared to $162 million in 2014;

Decreased storm costs at PECO and BGE of $78 million and $23 million, respectively;

Decreased uncollectible accounts expense at BGE of $23 million; and

A benefit in 2015 of $14 million for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy.

Depreciation and amortization expense increased by $86 million primarily as a result of the inclusion of CENG’s results on a fully consolidated basis in 2015 at Generation and ongoing capital expenditures across all registrants.

Taxes other than income increased by $21 million primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015.

Equity in earnings of unconsolidated affiliates increased by $17 million primarily due to CENG’s operating results being fully consolidated beginning April 1, 2014 and, as a result, are not reflected as equity method losses in 2015.

Gains on sales of assets decreased by $346 million primarily due to the gain on sale of Safe Harbor Water Corporation recorded in 2014.

Gain on consolidation and acquisition of businesses decreased by $261 million due to the gain recorded upon the consolidation of CENG in 2014, resulting from the difference in the fair value of CENG’s net assets as of April 2014, and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing transactions between Generation and CENG.

Interest expense increased by $33 million primarily as a result of higher outstanding debt at Generation and Exelon Corporate, and financing agreements related to the pending PHI merger at Exelon Corporate, partially offset by mark-to-market gains recorded in 2015 on forward-starting interest rate swaps related to the financing of the pending PHI merger recorded at Exelon Corporate as compared to losses recorded in 2014 and the favorable settlement in 2015 of an income tax position on Constellation’s pre-acquisition tax returns at Generation.

Other, net decreased by $525 million primarily as a result of the change in realized and unrealized gains and losses on NDT fund investments at Generation, favorable settlements in 2014 of certain income tax positions on Constellation’s pre-acquisition tax returns and a loss of $26 million on the termination of forward-starting interest rate swaps in 2015 at Exelon Corporate.

Exelon’s effective income tax rates for the nine months ended September 30, 2015 and 2014 were 29.1% and 27.2%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

For further detail regarding the financial results for the nine months ended September 30, 2015,March 31, 2016, including explanation of the non-GAAP measure revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.

Adjusted (non-GAAP) Operating Earnings.    Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2015March 31, 2016 were $757$632 million, or $0.83$0.68 per diluted share, compared with adjusted (non-GAAP) operating earnings of $676$615 million, or $0.78$0.71 per diluted share for the same period in 2014. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2015 were $1,880 million, or $2.13 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,646 million, or $1.91 per diluted share for the same period in 2014.2015. In addition to net income attributable to common shareholders, Exelon evaluates its operating performance using the measure of adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following table provides a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2015March 31, 2016 as compared to the same period in 2014.2015. The footnotes below the table provide tax expense (benefit) impacts:

 

   Three Months Ended September 30, 
   2015  2014 

(All amounts after tax)

     Earnings per
Diluted  Share
     Earnings per
Diluted  Share
 

Net Income Attributable to Common Shareholders

  $629   $0.69   $993   $1.15  

Mark-to-Market Impact of Economic Hedging Activities(a)

   85    0.09    (158  (0.18

Unrealized Losses Related to NDT Fund Investments(b)

   133    0.15    22    0.03  

Asset Retirement Obligation(c)

   (6  (0.01  (13  (0.02

Plant Retirements and Divestitures(d)

           (197  (0.23

Long-Lived Asset Impairment(e)

           30    0.03  

Merger and Integration Costs(f)

   12    0.02    58    0.06  

Amortization of Commodity Contract Intangibles(g)

   2        (12  (0.01

Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps(h)

           6    0.01  

Tax Settlements(i)

   (52  (0.06  (66  (0.08

CENG Noncontrolling Interest(j)

   (46  (0.05  13    0.02  
  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted (non-GAAP) Operating Earnings

  $757   $0.83   $676   $0.78  
  

 

 

  

 

 

  

 

 

  

 

 

 
   Three Months Ended March 31, 
   2016  2015 

(All amounts after tax)

     Earnings per
Diluted  Share
     Earnings per
Diluted  Share
 

Net Income Attributable to Common Shareholders

  $173   $0.19   $693   $0.80  

Mark-to-Market Impact of Economic Hedging Activities(a)

   (64  (0.07  (100  (0.11

Unrealized Gains Related to NDT Fund Investments(b)

   (31  (0.03  (24  (0.03

Merger and Integration Costs(c)

   76    0.08    21    0.02  

Merger Commitments(d)

   394    0.42          

Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps(e)

           48    0.06  

Long-Lived Asset Impairment(f)

   71    0.07          

Amortization of Commodity Contract Intangibles(g)

   (12  (0.01  (24  (0.03

Midwest Generation Bankruptcy Recoveries(h)

           (6  (0.01

Cost Management Program(i)

   14    0.02          

CENG Non-Controlling Interest(j)

   11    0.01    7    0.01  
  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted (non-GAAP) Operating Earnings

  $632   $0.68   $615   $0.71  
  

 

 

  

 

 

  

 

 

  

 

 

 

   Nine Months Ended September 30, 
   2015  2014 

(All amounts after tax)

     Earnings per
Diluted  Share
     Earnings per
Diluted  Share
 

Net Income Attributable to Common Shareholders

  $1,959   $2.22   $1,604   $1.86  

Mark-to-Market Impact of Economic Hedging Activities(a)

   (158  (0.18  293    0.34  

Unrealized (Gains) Losses Related to NDT Fund Investments(b)

   164    0.19    (62  (0.07

Asset Retirement Obligation(c)

   (6  (0.01  (13  (0.02

Plant Retirements and Divestitures(d)

           (197  (0.23

Impairment of Long Lived Assets(e)

   15    0.02    98    0.11  

Merger and Integration Costs(f)

   50    0.06    99    0.11  

Amortization of Commodity Contract Intangibles(g)

   (13  (0.01  42    0.06  

Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps(h)

   (21  (0.03  6    0.01  

Tax Settlements(i)

   (52  (0.06  (101  (0.12

Gain on CENG Integration(k)

           (159  (0.18

Midwest Generation Bankruptcy Recoveries(l)

   (6  (0.01        

CENG Noncontrolling Interest(j)

   (52  (0.06  36    0.04  
  

 

 

  

 

 

  

 

 

  

 

 

 

Adjusted (non-GAAP) Operating Earnings

  $1,880   $2.13   $1,646   $1.91  
  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

Reflects the impact of net (gains) losses for the three months ended September 30,March 31, 2016 and 2015 and September 30, 2014 (net of taxes of $54$39 million and $105$63 million, respectively) and the nine months ended September 30, 2015 and September 30, 2014 (net of taxes of $101 million and $188 million, respectively), on Generation’s economic hedging activities. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

(b)

Reflects the impact of net unrealized (gains) losses for Non-Regulatory Agreement Units and the contractual offset for taxes related to Regulatory Agreement Units and Pledged Assets for the three months ended September 30,March 31, 2016 and 2015 and September 30, 2014 (net of taxes of $148$35 million and $25$26 million, respectively) and the nine months ended September 30, 2015 and September 30, 2014 (net of taxes of $193 million and $22 million, respectively), on Generation’s NDT fund investments.investments for Non-Regulatory Agreement Units. See Note 1312 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

(c)

Reflects the impacts of a non-cash benefit pursuant to the annual update of Generation’s decommissioning obligation for the three and nine months ended September 30, 2015 and September 30, 2014 (net of taxes of $4 million for all periods).

(d)

Reflects the impact associated with the sale or retirement of Generation’s ownership interest in generating stations for the three and nine months ended September 30, 2014 (net of taxes of $132 million).

(e)

Reflects the 2015 charge to earnings for the nine months ended September 30, 2015 related to the impairment of investment in long-term leases (net of taxes of $9 million) and 2014 charges to earnings for the three and nine months ended September 30, 2014 related to the impairment of certain wind generating assets, certain generating assets held for sale, and investment in long-term leases (net of taxes of $20 million and $18 million, respectively).

(f)

Reflects certain costs incurred for the three months ended September 30,March 31, 2016 and 2015 and September 30, 2014 (net of taxes of $9$26 million and $20$13 million, respectively) and the nine months ended September 30, 2015 and September 30, 2014 (net of taxes of $32 million and $30 million, respectively) associated with the Constellation merger, pending PHI acquisition, and, at Generation, the CENG integration,, including professional fees, employee-related expenses, integration activities, upfront credit facilities fees, merger commitments, and certain pre-acquisition contingencies.contingencies, and the PHI acquisition. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs.

(d)

Reflects the costs incurred as part of the settlement orders approving the PHI acquisition (net of taxes of $114 million). See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.

(e)

For 2015, reflects the impact of net losses on forward-starting interest rate swaps at Exelon Corporate related to financing of the PHI acquisition (net of taxes of $31 million).

(f)

Reflects the impairment of Upstream assets at Generation in 2016 (net of taxes of $49 million).

(g)

Reflects the non-cash impact for the three months ended September 30,March 31, 2016 and 2015 and September 30, 2014 (net of taxes of $2 million and $2 million, respectively) and the nine months ended September 30, 2015 and September 30, 2014 (net of taxes of $7 million and $44$14 million, respectively), of the amortization of intangible assets, net, related to commodity contracts recorded at fair value atfor the Constellation merger and the Integryslntegrys acquisition.

(h)

Reflects the impact of losses (gains) on forward-starting interest rate swaps at Exelon Corporate related to financing of the pending PHI acquisition for the nine months ended September 30,For 2015, (net of taxes of $14 million) and the three and nine months ended September 30, 2014 (net of taxes of $4 million for both periods) .

(i)

Reflectsreflects a benefit related to the favorable settlement of certain income tax positions on Constellation’s pre-acquisition tax returns fora long term railcar lease agreement pursuant to the three months ended September 30, 2015 and September 30, 2014 (inclusiveMidwest Generation bankruptcy (net of taxes of $41 million$4 million).

(i)

For 2016, reflects the severance expense and $52 million, respectively) and the nine months ended September 30, 2015 and September 30, 2014 (inclusivereorganization costs related to a cost management program (net of taxes of $41 million and $70 million, respectively)$9 million).

(j)

Represents Generation’s non-controlling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments in 2015, and in 2014investments.

Merger and Acquisition Costs

On March 23, 2016, the Exelon and PHI Merger was completed. On the merger date, PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock. The resulting company will retain the Exelon name and be headquartered in Chicago.

As a result of the PHI Merger, Exelon has incurred and will continue to incur costs associated with evaluating, structuring and executing the PHI Merger transaction itself, meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former PHI businesses into Exelon.

The table below presents the one-time pre-tax charges recognized upon closing of the PHI Merger included in the Registrant’s respective Consolidated Statement of Operations and Comprehensive Income.

                                  Successor 
  Three Months Ended March 31, 2016   March 24,
2016 to
March 31,
2016
 
  Exelon   Generation   ComEd   PECO   BGE   Pepco   DPL   ACE   PHI 

Merger commitments

 $508    $3    $    $    $    $139    $104    $120    $363  

Employee related charges(a)

  71     12     1     1     1     27     16     13     56  

Changes in accounting and tax related policies and estimates(b)

                           25     15     5       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

 $579    $15    $1    $1    $1    $191    $135    $138    $419  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(a)

Primarily relates to severance, see Note 14 — Severance of the impact of unrealized gains and losses on NDT fund investments, certain merger and acquisition costs, and non-cash amortization of intangible assets, net, relatedCombined Notes to commodity contracts.Consolidated Financial Statements for additional information.

(k)(b)

Reflects the non-cash gain recorded upon consolidation of CENG in accordance with the executionPrimarily relates to income taxes, see Note 11 — Income Taxes of the NOSA on April 1, 2014Combined Notes to Consolidated Financial Statements for the nine months ended September 30, 2014 (net of taxes of $103 million).additional information.

(l)

Reflects a benefit related to the favorable settlement of a long term lease agreement pursuant to the Midwest Generation bankruptcy for the nine months ended September 30, 2015 (net of taxes of $4 million).

As

In addition to the one-time PHI Merger charges discussed above, Exelon has incurred costs associated with the Constellation merger, CENG integration, Integrys acquisition and pending PHI acquisition including employee-related expenses (e.g. severance, retirement, relocation and retention bonuses), integration initiatives, and certain pre-acquisition contingencies.

Forfor the three and nine months ended September 30, 2015 and 2014,March 31, 2016, expense has been recognized for merger, integration and acquisition costs incurred to achievefor the ConstellationPHI Merger and for the three months ended March 31, 2015, expense has been recognized primarily for merger, integration and acquisition costs for the PHI Merger, Integrys acquisition and CENG integration and the Integrys and pending PHI acquisitions as follows:

 

   Pre-tax Expense 
   Three Months Ended September 30, 2015 

Merger, Integration and Acquisition Costs:

  Generation   ComEd   PECO   BGE   Exelon 

Transaction(a)

  $    $    $    $    $5  

Other(b)

   10     3     1     2     17  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $10    $3    $1    $2    $22  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   Pre-tax Expense 
                                 Successor 
   Three Months Ended March 31, 2016   March 24,
2016 to
March 31,
2016
 

Merger, Integration and
Acquisition Costs:

  Exelon(a)  Generation(a)   ComEd  PECO   BGE   Pepco   DPL   ACE   PHI(a) 

Transaction(c)

  $35   $    $   $    $    $    $    $    $  

Employee-Related(d)

   71    12     1    1     1     27     16     13     56  

Other(e)

   (4  4     (9  1     1                      
  

 

 

  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $102   $16    $(8 $2    $2    $27    $16    $13    $56  
  

 

 

  

 

 

   

 

 

  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

   Pre-tax Expense 
   Three Months Ended September 30, 2014 

Merger and Integration Costs:

  Generation   ComEd   PECO   BGE   Exelon 

Financing(c)

  $    $    $    $    $11  

Regulatory Commitments(d)

   44                    44  

Other(b)

   18                    23  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $62    $    $    $    $78  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

   Pre-tax Expense 
   Nine Months Ended September 30, 2015 

Merger, Integration and Acquisition Costs:

  Generation   ComEd   PECO   BGE   Exelon 

Transaction(a)

  $    $    $    $    $14  

Financing(c)

                       21  

Other(b)

   30     9     4     4     49  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $30    $9    $4    $4    $84  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

  Pre-tax Expense   Pre-tax Expense 
  Nine Months Ended September 30, 2014   Three Months Ended March 31, 2015 

Merger and Integration Costs:

  Generation   ComEd   PECO   BGE   Exelon   Generation   ComEd   PECO   BGE   Exelon 

Financing(c)(b)

  $    $    $    $    $20    $    $    $    $    $89  

Regulatory Commitments(d)

   44                    44  

Transaction(c)

                       6  

Employee-Related(e)(d)

   5                    5     4                    4  

Other(b)(e)

   43                    60     7     3     1     1     13  
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total

  $92    $    $    $    $129    $11    $3    $1    $1    $112  
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

 

(a)

For Exelon, Generation and PHI, includes the operations of the acquired businesses from March 24, 2016 through March 31, 2016.

(b)

Reflects costs incurred at Exelon related to the financing of the PHI Merger, including upfront credit facility fees.

(c)

External, third party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of transactions.

(b)(d)

Costs primarily for employee severance, pension and OPEB expense and retention bonuses.

(e)

Costs to integrate CENG and Constellation processes and systems into Exelon and to terminate certain Constellation debt agreements. For the three and nine months ended September 30, 2015,March 31, 2016, also includes professional fees primarily related to integration for the proposed PHI acquisition.

(c)

Reflects (benefits) costs recorded at Exelon related to the financing of the PHI merger, including upfront credit facility fees. Excludes mark-to-market activity on forward-starting interest rate swaps.

(d)

Reflects costs incurred at Generation for a Constellation merger commitment.

(e)

Costs primarily for employee severance, pension and OPEB expense and retention bonuses.

As of September 30, 2015,March 31, 2016, Exelon projects incurringexpects to incur total PHI acquisition and integration related costs over the next five years of approximately $635$700 million, excluding the amountsmerger commitments. Of this amount, including 2014 and through March 31, 2016, Exelon and PHI are committed, if approved, to provide to the PHI utility’s respective customers.has incurred approximately $346 million. Included in this amount are costs to fund the acquisitionmerger of which $66$76 million has been expensed, $56 million has been paid and recorded as deferred debt issuance costs and $60 million has been incurred and charged to common stock. Also included is approximately $100 million for integration costs expected to be capitalized to Property, plant and equipment. Including 2014 and through September 30, 2015, Exelon has incurred approximately $226 million of expense associated with the proposed merger. The remaining costs will be primarily within Operating and maintenance expense within Exelon’s Consolidated Statements of Operations and Comprehensive Income.

Pursuant to the conditions set forth by the MDPSC in its approval of the ExelonIncome and Constellation merger transaction, Exelon committed to provide a package of benefits to BGE customers, and make certain investments in the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland ofwill also include approximately $1 billion. The direct investment estimate includes $95 million to $120$60 million for the requirement to cause construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. On March 20, 2013, Generation signed a 20-year lease agreement for office space that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. Construction began late in the second quarter of 2014 and the building isintegration costs expected to be ready for occupancy by the end of 2016.capitalized to Property, plant and equipment. See Note 194CommitmentsMergers, Acquisitions and ContingenciesDispositions of the Combined Notes to Consolidated Financial Statements for further information related toregarding the lease commitments.PHI acquisition.

Exelon’s Strategy and Outlook for the remainder of 20152016 and Beyond

Exelon’s value proposition and competitive advantage come from its scope and scale across the energy value chain and its core strengths of operational excellence and financial discipline. Exelon’s strategy is to leverageExelon leverages its integrated business model to create valuevalue. Exelon’s regulated and diversify its business. Exelon’s competitive and regulated businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:

 

Generation’s competitive businesses provide commodity exposure and a platform to diversify into adjacent markets, while providing residual dividend support.

Exelon’s utilities provide a foundation for stable earnings, and dividend support, which translates to a stable currency in our stock.

Generation’s competitive businesses provide free cash flow to invest primarily into the utilities and in long-term, contracted assets.

Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.

Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a net benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments prudently and at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.

Generation’s competitive businesses create value for customers by providing innovative solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide generation to load matching and that diversify the generation fleet to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.

Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a net benefit to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments prudently and at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of best practices to achieve improved operational and financial results. Additionally, ComEd, PECO and BGE anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.

Exelon’s financial priorities are to maintain investment grade credit metrics at each of Exelon, Generation, ComEd, PECO and BGE,the Registrants to maintain optimal capital structure and to return value to Exelon’s shareholders with a sustainablean attractive dividend throughout the energy commodity market cycle and through stable earnings growth from attractive investment opportunities.growth. Exelon’s Board of Directors approved a revised dividend policy. The approved policy raises our dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.

Various market, financial, and other factors could affect the Registrants’ success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. See ITEM 1A. RISK FACTORS of the Exelon 20142015 Form 10-K for additional information regarding market and financial factors.

Proposed Merger with Pepco Holdings, Inc. (Exelon)

On April 29, 2014, ExelonContinually optimizing the cost structure is a key component of Exelon’s financial strategy. Through a recent focused cost management program, the company has committed to reducing operation and Pepco Holdings, Inc. (PHI) signed an agreementmaintenance expenses and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Based on the outstanding shares of PHI’s common stock as of September 30, 2015, PHI shareholders would receive $6.9 billion in total cash. In addition, in connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $180capital costs by $350 million, of a classwhich approximately 35% of nonvoting, nonconvertible and nontransferable preferred securities of PHI. The preferred securitiesrun-rate savings are included in Other non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the rightexpected to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any.

On September 9, 2014, Exelon and PHI filed a Notification and Report Form with DOJ under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act). The HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the merger, the DOJ has not advised Exelon or PHI that it has concluded its investigation. Under the HSR Act, if the merger is not completed before December 23, 2015, Exelon and PHI are required to file again under the HSR Act and observe the required waiting periods, which is a minimum of 30 days from the new filing (and longer if the DOJ requests additional information), unless the DOJ terminates the waiting period earlier. Exelon and PHI may refile under the HSR Act in advance of December 23, 2015.

To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU), the Delaware Public Service Commission (DPSC), the Maryland Public Service Commission (MDPSC) and the FERC have approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses.

On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregate value of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million. The March 6, 2015, order by the NJBPU approving the merger required that the consummation of the merger must take place no later than November 1, 2015 unless otherwise extended by the Board. On October 15, 2015, the NJBPU extended the November 1, 2015 date to June 30, 2016.

On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the DPSC to review the proposed merger. The settlement, which was amended on April 7, 2015, was signed and filed by Exelon, PHI, Delmarva Power & Light Company (DPL), the DPSC Staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environment Control, the Delaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. As part of this settlement, Exelon and PHI proposed a package of benefits to DPL customers and the state of Delaware including the establishment of customer rate credits of $40 million for DPL customers in Delaware, $2 million of funding for energy efficiency programs for DPL low income customers, and $2 million of funding for workforce development. On June 2, 2015, the DPSC issued an order accepting the settlement and approving the merger between Exelon and PHI.

On March 17, 2015, Exelon and PHI announced that they had reached settlements with multiple parties in the Maryland proceeding to review the proposed merger after filing a Request for Adoption of Settlements with the MDPSC. The settlements were signed and filed by Exelon, PHI, Montgomery County, Prince George’s County, The Alliance for Solar Choice, the National Consumer Law Center, National Housing Trust, the Maryland Affordable Housing Coalition, the Housing Association of Nonprofit Developers, and a consortium of recreational trail advocacy organizations led by the Mid-Atlantic Off-Road Enthusiasts. On May 15, 2015, the MDPSC approved the merger after modifying a number of the conditions in the settlements, resulting in total rate credits of $66 million, funding for energy efficiency programs of $43.2 million, a Green Sustainability Fund of $14.4 million, 20 MWs of renewable generation development, ring-fencing, financial reporting conditions and increased penalties related to reliability commitments. On May 18, 2015, Exelon and PHI accepted and committed to fulfill the conditions.

On June 11, 2015, the Maryland Office of People’s Counsel (OPC), the Sierra Club, and the Chesapeake Climate Action Network filed Petitions for Judicial Review of the MDPSC’s approval of the merger with the Circuit Court for Queen Anne’s County. On June 23, 2015, Public Citizen, Inc. filed its Petition for Judicial Review with the Circuit Court for Queen Anne’s County. On July 10, 2015, Exelon and PHI filed a response in opposition to the Petitions for Review.

On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery and presentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 the Sierra Club and the Chesapeake Climate Action Network filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, Prince George’s County and Montgomery County filed responses opposing the motions to stay. The presiding judge issued an order denying the motions for stay on August 12, 2015. A hearing on the underlying Petitions for Review is scheduled for December 8, 2015.

On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of the merger, asserting that the merger was not in the public’s interest. Exelon and PHI

filed an Application for Reconsideration with the DCPSC on September 28, 2015. On October 6, 2015, Exelon, PHI, the District of Columbia Government, the Office of Peoples Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust — Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties) entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHI subsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of the Settlement Agreement and granting additional requested relief. The new package of benefits totals $78 million and includes commitments to provide relief of residential customer base rate increases of $26 million, one-time direct bill credits of $14 million, low-income energy assistance of $16 million, improved reliability, a cleaner and greener D.C. through funding energy efficiency programs and development of renewable energy, and investment in local jobs and the local economy through workforce development of $5 million. It also guarantees charitable contributions totaling $19 million over 10 years.

On October 28, 2015, the DCPSC at a public meeting agreed to reopen the approval application to allow for consideration of the Settlement Agreement and set a procedural schedule which would allow for completion of the merger in the first quarter of 2016. If the DCPSC does not approve the Settlement Agreement within the 150 day period after it was filed, either Exelon or PHI may terminate the Settlement Agreement.

The settlements reached and commission orders received to date in Delaware, Maryland and New Jersey include a “most favored nation” provision which, generally speaking, requires allocation of merger benefits proportionately across all the jurisdictions. When applying the most favored nation provision to the settlement terms and other conditions established in the merger approvals received to date, and as proposed in the Settlement Agreement filed with the DCPSC, Exelon and PHI currently estimate direct benefits of $430 million or more on a net present value basis (excluding charitable contributions and renewable generation commitments) will be provided, including rate credits, funding for energy efficiency programs, sustainability funds and other required commitments. Exelon and PHI anticipate substantially all of such amounts will be charged to earnings at the time of merger close and will be paidachieved by the end of 2017. An additional $50 million will be charged to earnings for charitable contributions, which are required to be paid over a period of 10 years. Commitments to develop renewable generation, which2016 and fully realized in 2018. Savings are expected to be primarily capital in nature, will be recognized as incurred. Upon completion of the merger, the actual nature, amount, timingallocated approximately 75%, 14%, 6% and financial reporting treatment for these commitments may be materially different from the current projection.

Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek6% to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. Exelon was also named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve all claims, which is subject to court approval. Final court approval of the proposed settlement is not anticipated until approximately 90 days after merger close. Exelon does not believe these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon’s results of operations.

Including 2014 and through September 30, 2015, Exelon has incurred approximately $226 million of expense associated with the proposed merger. Of the total costs incurred, $110 million is primarily related to acquisition and integration costs and $116 million is for costs incurred to finance the transaction. The financing costs include a net loss of $64 million related to the settlement of forward-starting interest-rate swaps. These swaps were terminated in connection with the $4.2 billion issuance of debt; refer to Note 10—Derivative Financial Instruments and Note 11— Debt and Credit Agreements for more information. The financing costs exclude costs to issue debt and equity.

During the three months ended September 30, 2015, Exelon, Generation, ComEd, PECO and BGE, incurred acquisition and integration costs, including financing costs, of $21 million, $9 million, $3 million, $2 million and $2 million, respectively. DuringExelon anticipates the nine months ended September 30, 2015, Exelon, Generation, ComEd, PECO and BGE incurred acquisition and integration costs of $47 million, $24 million, $10 million, $4 million and $5 million, respectively.

During the three months ended September 30, 2014, Exelon, Generation, ComEd, PECO and BGE incurred acquisition and integration costs, including financing costs, of $32 million, $3 million, $1 million, $1 million and $1 million, respectively. During the nine months ended September 30, 2014, Exelon, Generation, ComEd, PECO and BGE incurred acquisition and integration costs of $57 million, $4 million, $1 million,$1 million and $1 million, respectively.

The costs incurred are classified primarilyearnings per share savings impact on EPS will be within Operating and maintenance expense in the Registrants’ respective Consolidated Statement of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense.

The Merger Agreement also provides for termination rights for both parties. Exelon and PHI have entered into a Letter Agreement related$0.13 to the Settlement Agreement which has the practical effect of suspending their rights to terminate the Merger Agreement until November 20, 2015 if no schedule has been set by the DCPSC allowing for approval of the settlement by March 4, 2016, or until March 4, 2016, if a schedule is set for approval by March 4, 2016, but approval does not occur by that date. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging$0.18 from $259 million to $293 million plus certain expenses. If the Merger Agreement is terminated due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to $180 million (the amount of purchased nonvoting preferred securities of PHI described above), through the redemption by PHI of the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock, plus reimbursement of PHIs documented out-of-pocket expenses up to a maximum of $40 million.2018 forward.

Merger Financing

As of September 30, 2015, through the issuance of $5.4 billion of debt (including $1.15 billion of junior subordinated notes in the form of 23 million equity units), the issuance of $1.9 billion of common stock, and cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion), Exelon has sufficient cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments. See Note 11—Debt and Credit Agreements and Note 17—Common Stock for further information on the debt and equity issuances. See Note 4—Merger and Acquisitions of the Exelon 2014 Form 10-K for further information on the asset sales.

Exelon has listed various potential risks relating to the pending merger with PHI (see ITEM 1A. RISK FACTORS of the Exelon 2014 Form 10-K), including difficulties that may be encountered in satisfying the conditions to completion of the merger and the potential for developments that might have an adverse effect on Exelon and the ability to realize the expected benefits of the merger. Exelon is taking steps to manage these risks and expects that the merger can be completed on a basis favorable to the company’s shareholders and customers. Refer to Note 4 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the merger transaction.

Implications of Potential Early Plant Retirements

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions in New York and Illinois such as the recently proposed Zero Emission Standard element of the Next Generation Energy Plan (NGEP) or Low Carbon Portfolio Standard (LCPS) legislation in Illinois and Clean Energy Standard (CES) in New York, the impact of final

rules from the U.S. EPA requiring reduction of carbon and other emissions and the efforts of the states to implement those final rules, and the outcome of the Ginna RSSA hearing and settlement procedures and the resulting contractual terms and conditions. On September 10, 2015, after considering the results of the recent PJM capacity auctions, Exelon and Generation decided to defer for one year any decisions about the future operations of its Quad Cities and Byron nuclear plants and will offer both plants in the 2019/2020 auction in May 2016. As a result of clearing the other PJM capacity auction in September 2015 for the 2017/2018 transitional capacity auction, Exelon and Generation will continue to operate its Quad Cities nuclear power plant through at least May 2018. The Byron plant is already obligated to operate through May 2019. rules.

In addition, on October 29, 2015, Exelon and Generation decideddeferred retirement decisions on Clinton and Quad Cities until 2016 in order to defer any decision aboutparticipate in the future operations2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity auction to be held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois. In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price is insufficient to cover cash operating costs and a risk-adjusted rate of itsreturn to shareholders. The results of the 2019-2020 PJM capacity auction will be available on May 24, 2016.

On May 6, 2016 Exelon and Generation announced intentions to shut down the Clinton nuclear plant for one yearon June 1, 2017 and plan to bid theQuad Cities nuclear plant into the MISO capacity auction for the 2016/2017 planning year in March 2016. MISO’s announcement on October 27, 2015 acknowledging the need for market design changes in southernJune 1, 2018 if Illinois was a key factor in Exelon’s and Generation’s decision to defer for an additional year, among other factors such as positive results from the Illinois Power Agency’s capacity procurement fordoes not pass adequate legislation by May 31, 2016 and if Quad Cities does not clear the long-term impact of the EPA’s Clean Power Plan. The Clinton plant is currently obligated to operate through May 2016.2019-2020 PJM capacity auction. Exelon and Generation previously committed to cease operation of the Oyster Creek nuclear plant by the end of 2019. Exelon and Generation haveThe approved RSSA requires Ginna to continue operating through the RSSA term expiring in March 2017. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not made any decisions regarding potential nuclear plant closures at other sites at this time.adopted in New York. Refer to Note 5—Regulatory Matters for additional discussion on the Ginna RSSA.

As a result ofIn response to a decision to early retire one or more other nuclear plants, certain changes in accounting treatment would be triggered and Exelon’s and Generation’s results of operations and cash flows could be materially affected by a number of items including, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, contract termination fees, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, costs,relocation, retention, etc.), accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioning costs.trust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown. While there are a number of Generation’s nuclear plants that are at risk of early retirement, the

The following table provides the balance sheet amounts as of September 30, 2015March 31, 2016 for significant assets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement due to their current economic valuations and other factors:factors.

 

(in millions)  Quad Cities Clinton Ginna Total   Quad Cities Clinton Ginna Total 

Asset Balances

          

Materials and supplies inventory

  $49   $56   $30   $135    $47   $58   $30   $135  

Nuclear fuel inventory, net

   186    122    65    373     213    95    54    362  

Completed plant, net

   1,027    582    111    1,720     1,014    574    127    1,715  

Construction work in progress

   29    8    23    60     28    11    11    50  

Liability Balances

          

Asset retirement obligation

   (696  (396  (637  (1,729   (706  (407  (651  (1,764

NRC License Renewal Term

   2032    2046(a)   2029      2032    2046(a)   2029   

 

(a)

Assumes Clinton seeks and receives a 20-year operating license renewal extension.

In the event a decision is made to early retire one or more nuclear plants, theThe precise timing of the retirement date, and resulting financial statement impact, is uncertain and wouldmay be influencedaffected by a number of factors, such asincluding the results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations and just prior to its next scheduled nuclear refueling outage date in that year.

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the

end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then Generation would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available.

As of March 31, 2016, all three of Generation’s plants at the highest risk of early retirement (Quad Cities, Clinton, and Ginna) pass the NRC minimum funding test based on their current license lives. See Note 12—Nuclear Decommissioning for additional information on NRC minimum funding requirements. However, in the event of an early retirement just before their next individual refueling outages, it is estimated that Clinton and Ginna would no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. Quad Cities would also be at risk. A shortfall could require Exelon to post parental guarantees for Generation’s obligations. However, the amounts of any required guarantees will ultimately depend on the decommissioning approach adopted at each site (i.e., DECON, Delayed DECON and SAFSTOR), the associated level of costs, and the decommissioning trust fund investment performance going forward. Considering the three alternative decommissioning approaches available to Generation for each site, the most costly estimates currently anticipated could require parental guarantees of up to $385 million and $260 million for Clinton and Ginna, respectively, in order for each site to access its NDT fund for radiological decommissioning costs. Although Quad Cities is better positioned than the other two plants to avoid the need for a parental guarantee, if required, it could be up to $65 million in order for the site to access its NDT fund for radiological decommissioning costs.

In addition, upon issuance of any required financial guarantees, while all three sites would be able to utilize their respective decommissioning trust funds for radiological decommissioning costs which represents the majority of the total expected decommissioning costs, the NRC must approve an additional exemption in order for Generation to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by Generation. Accordingly, based on current projections, it is expected that some portion of the spent fuel management and/or site restoration costs would need to be funded through supplemental cash from Generation. While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under DOE reimbursement agreements or future litigation, across the three alternative decommissioning approaches available to Generation, for the next 10 years, Clinton and Ginna could incur spent fuel management and site restoration costs of up to $160 million and $115 million, net of taxes, respectively. The costs associated with Ginna would be shared by the plant co-owners at their respective ownership percentages. Quad Cities is better positioned to pass the test than the other two plants. Although considered unlikely, if Quad Cities fails the exemption test, at its ownership percentage Generation could be required to pay for spent fuel management costs of up to $180 million, net of taxes.

Power Markets

Price of Fuels.    The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, onwholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

Capacity Market Changes in PJM.    In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to

improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce theneed for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participated in the FERC proceedingincluding filing comments. On March 31, 2015, the FERC issued a Deficiency Order seeking further details regarding various aspects of the proposed reforms, but focused on the proposed default offer cap. In response, PJM acquiesced to modifications suggested by the Market Monitor addressing concerns about the default offer cap. On June 9, 2015, FERC approved PJM’s filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. PJM also sought approval from the FERC to delay the 2018/2019 RPM Base Residual Auction that would otherwise have been conducted in May, 2015. On April 24, 2015, the FERC issued an order allowing the delay. As a result of thesethis and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015).

MISO Capacity Market Results.On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation’s ratable hedging strategy, the results of the capacity auction arehave not expected to havehad a material impact on Exelon’s and Generation’s consolidated results of operations and cash flows.

InAdditionally, in late May and June 2015, a separate complaint wascomplaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, and Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants, other than Exelon or Generation, be investigated. Generation had an offer that was selected in the auction.

On October 1, 2015, the FERC announced that it was conducting a non-public investigation (that does not involve Exelon)Exelon or Generation) into whether market manipulation ofor other potential violations occurred related to the auction. On October 20,December 31, 2015, the FERC heldissued a technical conferencedecision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. The FERC ordered that certain rules must be changed for the next auction scheduled for April 2016 that will set capacity prices beginning June 1, 2016. In response to obtain further informationthis order, MISO must file certain rule changes with the FERC within 30 days and certain other changes within 90 days. The FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. The FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. On March 18, 2016, the FERC denied rehearing of its December 31, 2015 order in this matter. On April 14, 2016, the MISO released the results of the 2016/2017 capacity auction; the zone 4 region in downstate Illinois cleared the auction at a rate of $72 per MW per day. Clinton nuclear plant, which operates in the zone 4 region, cleared the auction and is committed to operate through May 31, 2017. See Note 7 — Implications of Potential Early Plant Retirements of the Combined Notes to the complaints. While it is too early to predictConsolidated Financial Statements for additional information on the outcomeimpacts of the complaint proceeding, Generation’s auction results could be impacted by its outcome.MISO announcement.

Additionally, MISO has acknowledged the need for capacity market design changes in the zone 4 region by posting an issues statement on October 27, 2015. MISOand stated that reforms to its capacity market process may be

required to drive future investment and that it plans to engage stakeholders to consider such reforms. See Note 8—Implications of Potential Early Plant Retirements for additional informationThe FERC has also encouraged such efforts, and Exelon has been working with MISO and its stakeholders on the impacts of the MISO announcement.such market changes.

Subsidized Generation.    The rate of expansion of subsidized generation, including low-carbon generation such as wind and solar energy, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.

Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices.

For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland, that it projected would be in commercial operation by June 1, 2015. CPV subsequently sought to extend that date. The CfD mandated that utilities (including BGE) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.

Exelon and others have challenged the constitutionality and other aspects of the New Jersey legislation aimed at suppressing capacity market prices in federal court. See Note 5 — Regulatory Matters for additional information on state specific actions taken in Maryland and theNew Jersey. Similar actions taken by the MDPSC were also challenged in statefederal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and federal courts. Ultimately, the Exelon parties prevailed in obtaining orders from the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth CircuitMaryland actions effectively undoinginvalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. However,Those decisions were upheld by the U.S. Court of Appeals. On April 19, 2016, the U.S. Supreme Court has agreed to reviewunanimously affirmed the matter,Fourth Circuit decision holding that the MDPSC’s required contracts are illegal and whileunenforceable. On April 25, 2016, the Court of Appeals decisions are helpful, there remains risk theU.S. Supreme Court will overruledenied certiorari concerning the lower Courts.Third Circuit decision. This denial of certiorari leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.

As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. In addition, CPV has announced its intention to move forward with construction of its New Jersey and Maryland plants, with or without the challenged state subsidy. Nonetheless, to the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have already artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon’s market driven position.auctions. While the court decisions in New Jersey and Maryland areSupreme Court decision is a positive developments,development, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s market driven position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.

One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that effectively allow these two companies to pass through to all customers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and its merchant generation affiliate. Collectively more than 6,000MW of primarily coal-fired generation owned by FE and AEP’s affiliates seek ratepayer guaranteed subsidies via the proposed Riders. Thus, the Riders are similar to the CfDs described above (except that the PPA Riders in Ohio would apply to certain existing generation facilities whereas the CfDs applied to new generation facilities). While AEP and FE initially filed for these Riders in 2013 and 2014, respectively, it was not until late 2015 that the proposals obtained meaningful traction when PUCO staff entered into a settlement and stipulation with the Ohio utilities supporting the proposals and recommending that the PUCO approve the Riders. Exelon is a participant in these proceedings. On March 31, 2016, PUCO issued separate orders generally approving each of the FE and AEP arrangements. In addition, separate complaints have been filed at the FERC pursuing federal causes of action (i) seeking to impose affiliate self-dealing requirements on the PPAs and (ii) seeking to impose a MOPR on the resources supporting the PPAs. On April 27, 2016, the FERC issued orders on the affiliate matter rescinding certain affiliate waivers previously granted to AEP and FE and requiring each to demonstrate that the PPAs (prior to transacting under them ) were entered into on an arms-length basis and do not reflect any affiliate preference. We do not expect such a showing could be made prior to PJM’s capacity auction that ends on May 24, 2016. Thus, it is unlikely the PPAs will impact the results of the upcoming auction. Nonetheless, further action by AEP and FE related to the PPAs is possible. In addition, the outcome of the MOPR complaint and its impact, if any, on Generation is not yet clear as it is too early in the proceeding to predict its outcome. Finally, Dayton Power and Light filed at PUCO seeking approval of similar arrangements.

Exelon has opposed the proposals in Ohio, continues to monitor developments in Maryland and participateNew Jersey and participates in stakeholder and other processes to ensure that similaronly appropriate state subsidies are not developed. In addition, Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to specific generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.

Energy Demand.    Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity for BGE no growth for PECO;and PECO and a decrease in projected load for electricity for ComEd.ComEd, Pepco, DPL and ACE. BGE, PECO, ComEd, Pepco, DPL and ComEdACE are projecting load volumes to increase (decrease) by 0.5%0.1%, 0.0% and0.4%, (0.2)%, (0.7)%, (0.3)% and (2.2)% respectively, in 20152016 compared to 2014.2015.

Retail Competition.    Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. The market

experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus weWe expect retailcompetitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.

Strategic Policy Alignment

Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.

Exelon’s boardBoard of directorsDirectors declared the first second, third and fourth quarter 20152016 dividends of $0.31 per share each on Exelon’s common stock. The dividends for the first second and third quarter were2016 dividend was paid on March 10, 2015, June 10, 20152016.

Exelon’s Board of Directors declared the second quarter 2016 dividends of $0.318 per share each on Exelon’s common stock and September 10, 2015. The fourth quarter dividend is payable on DecemberJune 10, 2015.2016. The dividend increased from the first quarter amount to reflect the Board’s decision to raise Exelon’s dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.

All future quarterly dividends require approval by Exelon’s boardBoard of directors.Directors.

Hedging Strategy

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 20152016 and 2016.2017. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of September 30, 2015,March 31, 2016, the percentage of expected generation hedged for the major reportable segments is 97%-100%96%-99%, 81%-84%69%-72% and 51%-54%37%-40% for 2015, 2016, 2017, and 2017,2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.

Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 50% of Generation’s uranium concentrate requirements from 20152016 through 20192020 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position.

ComEd, PECO and BGE

The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Growth Opportunities

Exelon is currently pursuing growth in both the utility and competitive energy businesses. Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas. By identifyingareas and capitalizing on emerging trends, Exelon plans to invest in new innovative technologies to compete with a new breed of energy players, with the expectation of leveraging those technologies to improve productivity and efficiencies within our existing businesses.offering sustainable returns.

Regulated Energy Businesses

The proposed acquisition ofcompleted merger with PHI provides an opportunity to accelerate Exelon’s regulated growth andto provide stable cash flows, earnings accretion, and dividend stability.support. Additionally, ComEd, PECO and BGEthe Utility Registrants anticipate investing approximately $16$25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $9$11 billion by the end of 2019. ComEd, PECO and BGE2020. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made prudently and at the lowest reasonable cost to customers.

See Note 5—5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.

Competitive Energy Businesses

Generation pursues growth in areas that take advantage of our existing core competencies. Generation continually assesses the optimal structure and composition of our generation assets as well as exploreexplores wholesale and retail opportunities. Generation identifiesopportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in long-term contracted generation across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, while identifying emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2015,March 31, 2016, Generation has currently approved plans to invest a total of $2.3approximately $2 billion in 2015 (full year)2016 through 20192018 on capital growth projects (primarily new plant construction and distributed generation). Additional growth opportunities continue to arise across the energy value chain.

Leveraging its competencies,

Generation’s 2014 acquisition of Integrys and Proliance retail energy marketing businesses allows Generation to expand its electric and gas retail footprint further in an industry sector that continues to mature and consolidate and provides hedging and diversification benefits to its existing portfolio.

Generation continues to prioritize investment opportunities in contracted generation across multiple technologies, including renewables.

Generation has a growing business in distributed generation that capitalizes on the trend toward a decentralized system and an increasing customer preference for clean energy.

The overall growth in natural gas supply is a key trend we expect to be sustained over the long term. Our upstream, midstream and LNG businesses will enable us to participate in that trend.

Liquidity

Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet Exelon and Generation’sits needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

Exelon, Generation, ComEd, PECO and BGEThe Registrants have access to unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.5 billion, $5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively.$9.5 billion. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion.$425 million. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below.

Exposure to Worldwide Financial Markets.    Exelon has exposure to worldwide financial markets including European banks. Disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of September 30, 2015,March 31, 2016, approximately 29%22%, or $2.5

$2.2billion, of the Registrants’ aggregate total commitments were with European banks. The credit facilitiesinclude $8.5$9.9 billion in aggregate total commitments of which $6.8$8.3 billion was available as of September 30, 2015,March 31, 2016, due to outstanding letters of credit and commercial paper.credit. There were no borrowings under the Registrants’ credit facilities as of September 30, 2015.March 31, 2016. See Note 11Liquidity and Capital ResourcesDebt and Credit Agreements of the Combined Notes to the Consolidated Financial StatementsMatters — Exelon Credit Facilities for additional information on the credit facilities.information.

Tax Matters

See Note 1211 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Environmental Legislative and Regulatory Developments.

Exelon supportsis actively involved in the promulgationEPA’s development and implementation of certain environmental regulations byfor the U.S. EPA, includingelectric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for electric generating units. Seeunits, as set forth in the discussion below for further details. The air and wastebelow. These regulations will have a disproportionate adverse impact on fossil-fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and will likely resulthave resulted in the retirement of older, marginal facilities. Retirements of coal-fired power plants will continue as additional EPA regulations take effect, and as air quality standards are updated and further restrict emissions. Due to theirits low emission generation portfolios,portfolio, Generation and CENG will not be significantly directly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been introduced in the U.S. Congress that would prohibit or impede the U.S. EPA’s rulemaking efforts. The timingefforts, and it is uncertain whether any of the consideration of such legislation is unknown.these bills will become law.

Air Quality.In recent years, the U.S. EPA has been implementing a series of increasingly stringent regulations under the Clean Air Act relatingapplicable to NAAQS for conventional air pollutants (e.g., NOx, SO2 and particulate matter) as well as stricter technology requirements to control HAPs (e.g., acid gases, mercury and other heavy metals) from electric generationgenerating units. The U.S. EPA continues to review and update its NAAQS with a tightened particulate matter NAAQS issued in December 2012 and a tightened ozone NAAQS issued on October 1, 2015. These recently finalized NAAQS updates will potentially resultregulations have resulted in more stringent emissions limits on fossil-fuel electric generating stations as states developimplement their compliance plansplans.

National Ambient Air Quality Standards (NAAQS).    The EPA continues to review and update its NAAQS for conventional air pollutants relating to ground-level ozone and emissions of particulate matter, SO2 and NOx. Following five years of litigation, the U.S. EPA considers future regulation updates to address interstate air pollution.

In July 2011,is finalizing the U.S. EPA published CSAPR and in June 2012, it issued final technical corrections. CSAPRCross State Air Pollution Rule that requires 28 upwind states in the eastern half of the United States to significantly improve air quality by

reducing power plant emissions that cross state lines and contribute to ground- levelground-level ozone and fine particle pollution in downwind states. On August 21, 2012, the D.C. Circuit Court held that the EPA had exceeded its authority in certain material aspects with respect to CSAPR

Mercury and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. On April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit Court decision and upheld CSAPR, and remanded the case to the D.C. Circuit Court to resolve the remaining implementation issues. On November 21, 2014, the U.S. EPA issued an Interim FinalAir Toxics Standard Rule in which the Agency announced that it was tolling the effective dates for the CSAPR. The first phase of the CSAPR program started on January 1, 2015, with the second phase starting January 1, 2017. On November 21, 2014 the Agency proposed CSAPR allowance allocations to generating units for the first five years of the program, 2015- 2020. These allowances were identical to those previously set forth in prior CSAPR rules. On remand the D.C. Circuit Court is reviewing the residual CSAPR challenges not addressed by the U.S. Supreme Court decision. On May 26, 2015, the D.C. Circuit Court issued its opinion on one of the residual CSAPR challenges and denied petitions to review EPA’s Kansas SIP disapproval, finding that the EPA had acted within the bounds of its delegated authority when it originally disapproved Kansas’ proposed state implementation plans (SIP)(MATS). On July 28, 2015 the D.C. Circuit Court released its opinion regarding the remaining challenges following the Supreme Court’s 2014 decision. In the opinion, the D.C. Circuit found that the original 2014 emission budgets challenged by petitioners were invalid and remanded them to EPA without vacatur. Note that the “2014” budgets were tolled to the 2017 compliance periods by EPA to address time lost during the litigation process. The budgets remanded include: the SO2 budgets for Texas, Alabama, Georgia, and South Carolina; and the NOx emissions budgets for Florida, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Texas, Virginia and West Virginia. Additionally, the court rejected claims to several broader challenges to CSAPR and denied the petitions with respect to those issues. EPA is currently evaluating its options with regard to reconsideration of these budgets.

In addition, on September 29, 2015, U.S. EPA sent to the Office of Management and Budget a draft of its proposed Interstate Transport Rule update to address the 2008 ozone NAAQS.

On December 16, 2011, the U.S. EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will havemetals, and to make capital investments in pollution control equipment and incur higher operating expenses. It is expected that owners of smaller, older, uncontrolled coal units will retire the units rather than make these investments, and a number of retirements have already occurred. Coal units with existing controls that do notThe initial compliance deadline to meet the MATS rulenew standards was April 16, 2015; however, facilities may need to upgrade existing controlshave been granted an additional one or add new controls to comply. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies, or retire the units.two year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. OnIn April 15, 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety.

In November 2014, On appeal, the U.S. Supreme Court granted a petition for review of the MATS Rule filed by 20 states and a coalition of coal-fired electric generators. Ondecided in June 28, 2015 the Supreme Court decided that the U.S. EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court of Appeals to take further action consistent with the U.S. Supreme Court’s opinion.opinion on this single issue. As such, the MATS rule remains in effect as of April 16, 2015; however, facilities may be granted an additional one or two year extension in limited cases. While it is possible that the D.C. Circuit Court will vacate or stay the rule, Exelon believes that the Supreme Court’s concerns can be quickly addressed without vacating the rule and affecting the compliance schedule. Exeloneffect.Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.

The U.S. EPA continued its regular, periodic review of the NAAQS standards, most recently issuing a revised ground-level ozone standard on October 1, 2015. The new 70 parts per billion (ppb) 8-hour average

standard represents a reduction from the 2008 ozone standard of 75 ppb. States will be required to submit area designations in October 2016, with final designations promulgated by EPA in 2017. Attainment dates range from 2020 through 2037. EPA projects that 241 counties exceeded the 70 ppb standard in 2015 and that only 14 counties (excluding California) will exceed the standard in 2025 as a result of the full suite of EPA emission regulations that have been, or will be, implemented by that time.

With regard to the 2008 ozone NAAQS, EPA issued findings on June 30, 2015, that 24 states, including Illinois, Massachusetts and Pennsylvania, have failed to submit complete “good neighbor” SIPs to demonstrate how each state will address its air pollution impacts on downwind states. These findings establish a 2-year deadline for EPA to either approve a SIP or finalize a Federal Implementation Plain (FIP) that addresses the “good neighbor” requirement of the Clean Air Act. On September 29, 2015, U.S. EPA sent to the Office of Management and Budget a draft of its proposed Interstate Transport Rule update to address the 2008 ozone NAAQS. In December 2012, the U.S. EPA issued its final revisions to the Agency’s particulate matter (PM) NAAQS. In its final rule, the U.S. EPA lowered the annual PM2.5 standard, but declined to issue a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its final rule that by 2020 it expects most areas of the country will be in attainment of the new PM2.5 NAAQS based on currently expected regulations, such as the MATS regulation.

In addition to these NAAQS, the U.S. EPA also finalized nonattainment designations for certain areas in the United States for the 2010 one-hour SO2 standard on August 5, 2013, and indicated that additional nonattainment areas will be designated in a future rulemaking. U.S. EPA required states to submit SIP for nonattainment areas by March 25, 2015. With regard to Texas and Maryland, no nonattainment areas were identified in EPA’s final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. Since the 2010 one-hour SO2 standard was finalized, EPA has issued a series of guidance documents that relate to requirements for states to include air quality monitoring and modeling in state implementation plans. Nonattainment county compliance with the one-hour SO2 standard is required by March 25, 2018. On August 10, 2015, EPA issued its final “Data Requirements Rule” that lays out EPA’s plan for designating currently undesignated areas that heretofore have not been designated due primarily to a lack of available monitoring data. Under this plan, all currently undesignated areas receiving a designation no later than 2020; included in the consent decree is a requirement that all large emission plants achieve emissions of less than 2,000 tons per year by 2017. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states’ SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard.

The cumulative impact of these air regulations could be to require fossil fuel-fired power plant operators to expend significant capital to install pollution control technologies, including wet flue gas desulfurization technology for SO2 and acid gases, and selective catalytic reduction technology for NOx.

As of September 30, 2015, Exelon had a $348 million net investment in coal-fired plants in Georgia subject to long-term leases extending through 2028 and 2030. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, after reflecting impairments recorded in 2013, 2014, and 2015, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material.

On January 15, 2013, EPA issued a final rule for NSPS and National Emissions Standards for Hazardous Air Pollutants (NESHAP) for reciprocating internal combustion engines (RICE NESHAP/ NSPS). The final rule allowed diesel backup generators to operate for up to 100 hours annually under certain emergency circumstances without meeting emissions limitations, but required units that operate over 15 hours to burn low sulfur fuel and report key engine information. The final rule eliminated, after May 2014, the 50 hour exemption for peak shaving and other non-emergency demand response that was included in the proposed rule and, therefore, was not expected to result in additional megawatts of demand response to be bid into the PJM capacity auction. On

May 1, 2015, the D.C. Circuit Court reversed the 100 hour exemption contained in the 2013 RICE NESHAP final rule and remanded this issue back to EPA, leaving the remaining portions of the 2013 RICE NESHAP rule in effect. In a motion filed on July 15, 2015, EPA and respondent intervenors supporting EPA asked the D.C. Circuit Court to stay the Court’s mandate with regard to the 100 hour exemption until May 1, 2016, or in the alternate, until at least August 31, 2015 on the claimed basis of the need to consider electric grid reliability and allow affected engines to install pollution control equipment if they intend to continue participation in demand response programs. On July 21, 2015, the D.C. Circuit Court responded to a separate motion with the clarification that the 100 hour exemption vacatur did not affect the 100 hour exemption with regard to units performing maintenance checks and readiness testing.

Climate Change.Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with

economywith the urgent need to reduce national GHG emissions. In the absence of Federalfederal legislation, the U.S. EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. On June 25, 2013, President Obama announced “The President’s Climate Action Plan,” a summaryIn addition, there have been recent developments in the international regulation of executive branch actions intended to: reduce carbon emissions; prepareGHG emissions pursuant to the United States for the impactsNations Framework Convention on Climate Change (“UNFCCC” of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement“Convention”). See ITEM 1. BUSINESS, “Global Climate Change” of the Administration’s plan, the President also issued a MemorandumExelon 2015 Form 10-K for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions for new and existing units under Section 111 of the Clean Air Act. On August 3, 2015, the U.S. EPA finalized the Clean Power Plan rule for existing generation units. The rule was published in the Federal Register on October 23, 2015, and will become effective on December 22, 2015. The rule sets GHG emission reduction targets for each state, with reductions beginning in 2022, and the target achieved by 2030. States must submit an implementation plan to the U.S. EPA by September 2016, unless granted an extension of up to two years. States are granted latitude to select from a number of compliance options, which are designed to achieve the reductions in the most cost-effective manner. While the ultimate impact of the Clean Power Plan rule is expected to be favorable, Exelon and Generation cannot at this time predict to what extent the states’ actions to comply with the Clean Power Plan’s emission reduction targets will impact their future financial position, results of operations and cash flows.

Upon publication in the Federal Register a number of parties, including states, members of the electric industry and industry associations, filed suit in the U.S. Court of Appeals for the District of Columbia Circuit challenging the rule and seeking a stay of the rule pending the outcome of litigation.further discussion.

Water Quality.Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s and CENG’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, thoseThose facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna. On October 14, 2014, the U.S. EPA’s final Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed at each facility to determine the best technology available, followed by an implementation period. The timingSee ITEM 1. BUSINESS, “Water Quality” of the various requirementsExelon 2015 Form 10-K for each facility is related to the status of its current NPDES permitfurther discussion.

Solid and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, the impact of compliance with the final rule is unknown. Should a state permitting director determine that a facility is required to install cooling towers to comply with the rule, that facility’s

economic viability would be called into question. However, the likely impact of the rule has been significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director is required to apply a cost-benefit test and take into consideration site-specific factors.

On June 30,Hazardous Waste.    In October 2015, NJDEP issued a draft NPDES permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to continue to operate utilizing the existing once-through cooling water system. The draft permit is subject to a public notice and comment period after which the NJDEP may make revisions before issuing the final permit expected during the first half of 2016.

Hazardous and Solid Waste.On December 19, 2014, the U.S. EPA issued the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants including the classification ofbecame effective. The rule classifies CCR as non-hazardous waste under RCRA. The EPA ruling was published in the Federal Register on April 17, 2015, and became effective 180 days after publication. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federalregulationsfederal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable topredictto predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.

See Note 1918 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters.matters, including the impact of environmental regulation.

Other Regulatory and Legislative Actions

NRC Task Force Insights from the Fukushima Daiichi Accident (Exelon and Generation).    In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. The NRC and its staff are continuing to evaluate additional requirements. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under review by the NRC staff, both from an operational and a financial impact standpoint. A comprehensive review of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of compliance for Generation, net of expected co-owner reimbursements, for the period from 2015 through 2019 is expected to be between approximately $350 million and $375 million of capital (which includes approximately $75 million for the CENG plants) and $50 million of operating expense (which includes approximately $5 million for the CENG plants). Generation has included in the capital estimate approximately $30 million for severe accident water addition and severe accident water management strategies at thirteen Mark I and II units (including two CENG units). On August 19, 2015, the NRC voted to stop pursuing the possibility of requiring drywell vents and standalone filters on vents. The severe accident water management strategies effectively eliminate the need for installation of drywell vents and standalone filters on vents. As Generation completes the design and installation planning for its actions, Generation will update these estimates. Generation’s current assessments are specific to the Tier 1 recommendations as the NRC has not taken specific action with respect to the Tier 2 and Tier 3 recommendations. Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions and stakeholder input. See Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Executive Overview of the Exelon 2014 Form 10-K, for additional information.

Financial Reform Legislation (Exelon, Generation, ComEd, PECO and BGE).    The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that applies to Exelon is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires the creation of a new regulatory regime for over-the-counter swaps (Swaps), including mandatory clearing for certain categories of Swaps, incentives to shift Swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. For non security-based Swaps including commodity Swaps, Dodd-Frank empowers the Commodity Futures Trading Commission (CFTC) to promulgate regulations implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the key intermediaries in the Swaps market, which entities are either swap dealers (SDs), major swap participants (MSPs), and certain other financial entities, but the law also applies to a lesser degree to end-users of Swaps. On January 12, 2015, President Obama signed into law a bill that exempts from margin requirements Swaps used by end-users to hedge or mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energy industry to hedge their risks using Swaps without being subject to mandatory clearing, and excepts or exempts end-users from many of the other substantive regulations. Accordingly, as an end-user, Generation is conducting its commercial business in a manner that does not require registration with the CFTC as an SD or MSP. Generation does not anticipate transacting in the future in a manner in which it would become a SD or MSP.

There are, however, some rulemakings that have not yet been finalized, including the capital and margin rules for (non-cleared) Swaps. Generation does not expect these rules to directly impact its collateral requirements. However, depending on the substance of these final rules in addition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, Generation’s Swap counterparties could be subject to additional and potentially significant capitalization requirements. These regulations could motivate the SDs and MSPs to increase collateral requirements or cash postings from their counterparties, including Generation.

Generation continues to monitor the rulemaking proceedings with respect to the capital and margin rules, but cannot predict to what extent, if any, further refinements to Dodd-Frank requirements may impact its cash flows or financial position, but such impacts could be material.

ComEd, PECO and BGE could also be subject to some Dodd-Frank requirements to the extent they were to enter into Swaps. However, at this time, management of ComEd, PECO and BGE continue to expect that their companies will not be materially affected by Dodd-Frank.

Illinois Low Carbon Portfolio Standard (Exelon, Generation and ComEd).    In March 2015, the Low Carbon Portfolio Standard (LCPS) was introduced in the Illinois General Assembly. The legislation would require ComEd and Ameren to purchase low carbon energy credits to match 70 percent of the electricity used on the distribution system. The LCPS is a technology-neutral solution, so all generators of zero or low carbon energy would be able to compete in the procurement process, including wind, solar, hydro, clean coal and nuclear. Costs associated with purchasing the low carbon energy credits would be collected from customers. The LCPS proposal includes consumer protectionprotections such as a price cap that would limit the impact to a 2.015% percent increase based off 2009 monthly bills, or about $2 per month for the average residential electricity customer.customer, similar to the cost cap protection under other clean energy programs in Illinois. The legislation also includes a separate customer rebate provision that would provide a direct bill credit to customers in the event wholesale prices exceed a specified level. The proposed legislation isremains pending andalong with two other major energy bills. Exelon and Generation continue to work with stakeholders.stakeholders on a comprehensive energy package.

Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greener Illinois (Exelon and ComEd).    In March 2015, legislation was introduced in the Illinois General Assembly that would (1) build on ComEd’s investment in the Smart Grid to reinforce the resiliency and security of the electrical grid towithstand unexpected challenges, (2) expand energy efficiency programs to reduce energy waste and increase customer savings, (3) further integrate clean renewable energy onto the power system, and (4) introduce a new demand-based rate design for residential customers that would allow for a more equitable sharing of smart grid

costs among customers. The legislation also provides for additional funding for customer assistance programs for low-income customers. The proposed legislation is pending and ComEd continues to work with stakeholders.

Next Generation Energy Plan (Exelon, Generation and ComEd).    On May 5, 2016, the Next Generation Energy Plan was introduced in the Illinois General Assembly. The legislation contains significant parts of the previously introduced Illinois Low Carbon Portfolio Standard and Legislation to Maximize Smart Grid Investments and to Promote a Cleaner and Greater Illinois, along with new elements. The legislation includes (1) a Zero Emission Standard providing compensation for at-risk nuclear plants that demonstrate their revenues are insufficient to cover their costs, (2) $1 billion of funding for low-income assistance, including $650 million for energy efficiency programs, $250 million in Renewable Energy Resource Funds, $50 million in Percentage of Income Payment Plan funding and utility bill assistance, and $50 million in ComEd CARE, (3) $140 million in new funding for solar development and a new solar rebate to incent solar generation, (4) additional investment at ComEd to enhance reliability and security of the power grid, (5) an expansion of the Renewable Portfolio Standard, and (6) a 50% reduction in the fixed customer charge for energy delivery creating more equitable rates across customers. The proposed legislation is pending and Exelon, Generation, and ComEd continue to work with stakeholders. See Note 7 — Implications of Potential Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.

Distribution Formula Rate Update Filing (Exelon and ComEd).    On April 15, 2015,13, 2016, ComEd filed its annual distribution formula rate with the ICC, reflectingrequesting a decreasedtotal increase to the revenue requirement of $50$138 million, includingreflecting an increase of $92$139 million for the initial revenue requirement for 2017 and a decrease of $142$1 million related to the annual reconciliation for 2014. On October 19, 2015, the ALJ issued its proposed order in ComEd’s current distribution formula rate proceeding, recommending a total decrease to the revenue requirement of $68 million as compared to ComEd’s requested decrease of $50 million.2015. The filing establishes the revenue requirement used to set the rates that will take effect in January 20162017 after the ICC’s review and approval, which is due by December 2015.2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to distribution formula update.updates.

2015 Pennsylvania2016 Maryland Electric Distribution Base Rate Case (Exelon, PHI and PECO)Pepco).On March 27, 2015, PECOApril 19, 2016, Pepco filed a petitionan application with the PAPUCMDPSC requesting an increase of $190$127 million to its annual service revenues for electric delivery. Pepco requested ROE for the electric distribution rate case of 10.6%. Any adjustments to rates approved by the MDPSC are expected to take effect in 2016. In addition to the proposed $127 million rate increase, Pepco is proposing to continue its Grid Resiliency Charge initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. In connection with the Grid Resiliency Charge, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict how much of the requested increase the MDPSC will approve or if it will approve Pepco’s Grid Resiliency Charge proposal.

2016 Electric Distribution Base Rates (Exelon, PHI and ACE).    On March 22, 2016, ACE filed an application with the NJBPU requesting an increase of $84 million to its annual service revenues for electric delivery, whichbased on a requested an ROE of 10.95%10.6%. In addition to the request for base rate relief, ACE has also included a request that the NJBPU approve ACE’s five-year grid resiliency initiative known as “PowerAhead.” As proposed, PowerAhead includes $176 million of capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system’s ability to withstand major storm events. A decision is expected in the first half of 2017. ACE cannot predict how much of the requested increase the NJBPU will approve or if it will approve ACE’s PowerAhead initiative.

2015 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE).    On September 10,November 6, 2015, PECO and interested partiesas amended in the first quarter of 2016, BGE filed for electric and gas base rate increases with the PAPUC a petition for joint settlement forMDPSC,ultimately requesting an increase of $127$118 million in annualand $79 million respectively, of which $104 million and $37 million, respectively, is related to recovery of smart grid initiative costs. BGE requested a ROE for the electric and gas distribution service revenue. Nooverall ROE was specified in the settlement. On October 28, 2015, the ALJ issued a Recommended Decision to the PAPUC that the joint settlement be approved. A final ruling from the PAPUC is expected by December 2015,rate case of 10.6% and if approved, the10.5% respectively. The new electric deliveryand gas base rates willare expected to take effect on January 1,in June 2016. BGE is also proposing to recover an annual increase of approximately $30 million for Baltimore City conduit lease fees through a surcharge. BGE cannot predict how much of the requested increase the MDPSC will approve or if it will approve BGE’s request for a conduit fee surcharge.

Transmission Formula Rate Update Filing (Exelon, ComEd and BGE).On April 15, 2015 (and revised on May 19, 2015),13, 2016, ComEd filed its annual transmission formula rate update with the FERC, reflecting an increased revenue requirement of $86$94 million, including an increase of $68$90 million for the initial revenue requirement for 2016 and an increase of $18$4 million related to the annual reconciliation for 2014.2015. The filing establishes the revenue requirement used to set rates that tookwill take effect in June 2015,2016, subject to review by the FERC and other parties, which is due by fourth quarter 2015.October 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information related to transmission formula update.

InOn April 2015,27, 2016, BGE filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC reflecting an increasedand other parties, which is due by third quarter 2016. BGE’s 2016 annual update includes a total increase to the revenue requirement of $10$15 million, includingreflecting an increase of $13$12 million for the initial revenue requirement and a decrease of $3 million related to the annual reconciliation for 2014. The filing establishesreconciliation. This increase excludes the $13 million increase in revenue requirement used to set rates that took effect in June 2015, subject to review by other parties, which is due by October 2015. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statementsassociated with dedicated facilities charges. The revenue requirement provides for further information related to the transmission formula update.

Grand Prairie Gateway Transmission Line (Exelona weighted average debt and ComEd).    On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’sequity return on transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100%base of its prudent costs incurred after May 21, 2014 and 50%8.09%, inclusive of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. The costs incurred for the project prior to May 21, 2014 were immaterial. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie Gateway Project over the objectionallowed ROE of numerous landowners and the City of Elgin. On January 15, 2015, the City of Elgin and other parties filed10.50% a Notice of Appeal in the Illinois Appellate Court. On April 8, 2015, the ICC issued a rehearing order denying the proposals filed by certain landowners to consider an alternate route for a three-mile segment of the transmission line. The rehearing order affirmed the route approved within the ICC’s October 22, 2014 order. On July 8, 2015,the ICC approved ComEd’s request for eminent domain to involuntarily acquire easements across 28 land parcels. On September 28, 2015, ComEd filed a petition with the ICC to acquire an additional eight parcelsthrough eminent domain. ComEd began construction of the line during the second quarter of 2015 with an in-service date expected in the second quarter of 2017.

FERC Ameren Order (Exelon and ComEd).    In July 2012, FERC issued an order to Ameren Corporation (Ameren) finding that Ameren had improperly included acquisition premiums/goodwill in its transmission formula rate, particularly in its capital structure and in the application of AFUDC. FERC also directed Ameren to make refunds for the implied increase in rates in prior years. Ameren filed for rehearing of the July 2012 order, which was denied in June 2014. On July 20, 2015, FERC approved a settlement between Ameren and its customers to resolve the matter. ComEd believes that the FERC settlement authorizing its transmission formula rate is distinguishabledecrease from the circumstances that led to the July 2012 FERC order in the Ameren case. However, if ComEd were required to exclude acquisition premiums/goodwill from its transmission formula rate, the impact could be material to ComEd’s results of operations8.46% average debt and cash flows.

FERC Order No. 1000 Compliance (ComEd, PECO and BGE).    In FERC Order No. 1000, the FERC required public utility transmission providers to enhance their transmission planning procedures and their cost allocation methods applicable to certain new regional and interregional transmission projects. As part of the changes to the transmission planning procedures, the FERC required removal from all FERC-approved tariffs and agreements of a right of first refusal to build certain new transmission facilities. On October 25, 2012, certain of the PJM transmission owners, including ComEd, PECO and BGE (collectively, the PJM Transmission Owners), submitted a filing asserting that their contractual rights embodied in the PJM governing documents continue to justify their right of first refusal to construct new reliability (and related) transmission projects and that the FERC should not be allowed to override such rights absent a showing that it is in the public interest to do so under the FERC’s “Mobile-Sierra” standard of review. This is a heightened standard of review which the PJM Transmission Owners argued could not be satisfied based on the facts applicable to them. On March 22, 2013, FERC issued an order that, among other things, rejected the arguments of the PJM Transmission Owners that changes to the PJM governing documents were entitled to review under theMobile-Sierra standard. The FERC’s March 22, 2013 order could enable third parties to seek to build certain regional transmission projects that hadequity return previously been reserved for the PJM Transmission Owners, potentially reducing ComEd, PECO and BGE’s financial return on new investments in energy transmission facilities.

Numerous parties sought rehearing of the FERC’s March 22, 2013 order, including the PJM Transmission Owners. On May 15, 2014, FERC denied the PJM Transmission Owner rehearing request. Several parties filed an appeal of the FERC’s May 15, 2014, Order upholding PJM’s right of first refusal language in the D.C. Circuit. The ultimate outcome of this proceeding cannot be predicted at this time, however, could be material to Exelon, ComEd, PECO and BGE’s results of operations and cash flows.authorized.

FERC Transmission Complaint (Exelon, BGE, PHI, Pepco, DPL and BGE)ACE).    OnIn February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE, Pepco, DPL and the PHI companiesACE relating to their respective transmission formula rates. BGE’s formula rate includesincluded a 10.8% base ROErate of return on common equity (ROE) and a 50 basis point incentive for participating in PJM (the latter(and certain additional incentive base points on certain projects). Pepco’s, DPL’s and ACE’s formula rates included, for facilities placed into service after January 1, 2006, a base ROE of which is conditioned upon crediting the first11.3%, and for facilities placed into service prior to January 1, 2006, a base ROE of 10.8% and a 50 basis points of anypoint incentive ROE adders).for participating in PJM. The parties seeksought a reduction in the base ROEreturn on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, theany revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint.

On August 21, 2014, FERC issued an order in the BGEBGE’s, Pepco’s, DPL’s and PHI companies’ACE’s proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013. BGE,

On February 23, 2016, FERC approved the PHI companies andsettlement filed by the parties beganon November 6, 2015, covering the ROE issues raised in the complaints. The settlement discussions underprovides for a 10% base ROE, effective March 8, 2016, which will be augmented by the guidancePJM incentive adder of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the Settlement Judge informed FERC50 basis points, and the Chief Judge that the parties had reached an impasserefunds to BGE , Pepco, DPL and determined that aACE customers of $13.7 million, $14.2 million, $11.9 million and $9.5 million, respectively. The settlement was not possible. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at the hearings and directing that an initial decision be issued by November 25, 2015.

On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regardingalso prohibits any settling party from filing to change the base ROE of the transmission business seeking a reduction from 10.8%or any incentives prior to 8.8%.June 1, 2018. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants’ requested refund effective date of December 8, 2014. On February 20, 2015, the Chief Judge issued an order consolidating the two complaint proceedings and established an Initial Decision issuance deadline of February 29, 2016. On March 2, 2015, the Presiding Administrative Law Judge issued an order establishing a procedural schedule for the consolidated proceedings that provides for the hearing to commence on October 20, 2015. On September 14, 2015, the complainants and respondents filed a joint motion to suspend the hearing schedule because they have reached a settlement in principle to resolve the ROE issue. On September 15, 2015, the Chief Administrative Law Judge issued an order granting the motion, and setting October 15, 2015 as the date for the moving parties to either file a settlement or file a status report detailing the timetable for filing a settlement, which was subsequently extended to October 30, 2015. On October 30, 2015,request for rehearing has expired without any such requests having been filed. Accordingly, the parties filed a status report stating their intent to either file a settlement or file another status report duringorder is not eligible for appeal and the fourth quarter of 2015.

Based on the current status of the complaint filings, BGE believes itmatter is probable that BGE’s base ROE rate will be adjusted, and that a refund to customers of transmission revenue for the two maximum fifteen month periods will be required. BGE has established a reserve, which management believes is adequate for what it considers to be the most likely outcome. The estimated annual ongoing reduction in revenues if FERC approved the ROEs as originally requested by the parties in their initial filings is approximately $11 million. If FERC were to order a reduction of BGE’s base ROE to 8.7% and 8.8% as sought in the first and second complaints, respectively (while retaining the 50 basis points of any incentives that were credited to the base ROE for certain new transmission investment), the result would be a refund to customers of approximately $13 million and $14 million for the first and second fifteen month refund windows, respectively, for a total refund to customers of $27 million.considered closed. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

The Maryland Strategic Infrastructure Development and Enhancement ProgramConduit Lease with City of Baltimore (Exelon and BGE).    In February 2013,.    On September 23, 2015, the Maryland General Assembly passed legislation intendedBaltimore City Board of Estimates approved an increase in rental fees for access to accelerate gas infrastructure replacementsthe Baltimore City conduit system to beeffective November 1, 2015, which is expected to result in Marylandan increase to Operating and maintenance expense of approximately $25 million in 2016 subject to an annual increase based on the Consumer Price Index. On October 16, 2015, BGE filed a lawsuit against the City in the Circuit Court for Baltimore City to protect its customers from any improper use by establishingthe City of the conduit fee revenues and to place constraints on the City’s ability to set the conduit fee in the future.

Among the relief sought by BGE was a mechanismpreliminary injunction preventing the City from enforcing its substantial increase in the conduit fee rate during the course of the litigation. A hearing was held in the Circuit

Court for gas companies to promptly recover reasonableBaltimore County on December 15, 2015. While BGE’s motion for preliminary injunction was denied, the Court’s decision was premised upon several important concessions or acknowledgments made by the City in its written papers and prudentat the hearing. Most importantly, the City conceded that it can charge BGE only for the actual costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, followingconduit maintenance and that a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGEprocess is required to file athe extent that the City fails to spend the amount collected for conduit maintenance.

As part of its electric and gas distribution rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement planon November 6, 2015, and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approvingas amended in the first five yearsquarter of BGE’s plan and surcharge. On March 26, 2014,2016, BGE is proposing to recover the MDPSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that becameannual increase in conduit fees effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update to be effective January 1, 2015 includingof approximately $30 million through a true-up of costs estimates included in the 2014 surcharge, along with its 2015 project list and projected capital estimates of $78 million to be included in the 2015 surcharge calculation. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE’s 2015 project list and the proposed surcharge for 2015, which included the true-up of the 2014surcharge. As of September 30, 2015, BGE recorded a regulatory asset of $1 million, representing the difference between the surcharge revenues and program costs.

In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement plan. On September 5,

2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE’s infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court. During the third quarter of 2015, the residential consumer advocate, MDPSC, and BGE filed briefs. The Court of Special Appeals has set oral argument in this matter for November 3, 2015. BGE cannot predict the outcome of this appeal. However, if the consumer advocates appeal is successful, BGE could seek recovery of infrastructure replacement costs through other regulatory mechanisms. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial StatementsMDPSC will approve BGE’s request for additional information.

PJM Minimum Offer Price Rule (Exelon and Generation).    PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014.

Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM.conduit fee surcharge.

Employees

During 2015, Generation successfully ratifiedthe first quarter of 2016, the collective bargaining agreement (CBA) between the IBEWComEd and Clinton Power Station through 2021, the CBA with that Security Officer union at Braidwood, Byron and Three Mile Island through 2018, 2019, and 2021, respectively. In addition, two union contracts at Mystic 7 and Mystic 8/9 were successfully negotiated and ratified through 2021.

Negotiations for a first contract of the ComEd Distribution Testing Technicians (DT), a group of 49 technicians represented by IBEW Local 15, which represents the ComEd’s System Services Group, was successfully ratified. After a two-year transition period ending Decemberfurther extended to May 31, 2017, the DT group will cease2016. In addition, Exelon added 5,174 total employees from its merger with PHI and its subsidiaries, of which 2,725 are covered by CBAs. PHI’s utility subsidiaries are parties to exist and mostfive CBAs with four local unions. All of the existing duties will be absorbed by existing represented work group positions within the current ComEd IBEW Local 15 CBA, which will expire on September 30, 2019.CBAs were renegotiated in 2014, and were extended through various dates ranging from October 2018 through June 2020.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’s combined 20142015 Form 10-K and PHI’s, Pepco’s, DPL’s and ACE’s 2015 combined Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition, and allowance for uncollectible accounts. At September 30, 2015,March 31, 2016, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2014.2015.

Results of Operations

Net Income Attributable to Common Shareholders by Registrant

 

 Three Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
   Three Months Ended
March 31,
   Favorable
(Unfavorable)
Variance
 
      2015(a)         2014          2015(a)         2014            2016(a)         2015       

Exelon

 $629   $993   $(364 $1,959   $1,604   $355    $173   $693    $(520

Generation

  377    771    (394  1,218    926    292     310    443     (133

ComEd

  149    126    23    339    335    4     115    90     25  

PECO

  90    81    9    299    255    44     124    139     (15

BGE

  51    46    5    202    146    56     98    106     (8

Pepco

   (108  26     (134

DPL

   (72  32     (104

ACE

   (100  9     (109

 

(a)

On April 1, 2014,For Pepco, DPL and ACE, reflects that Registrant’s operations for the three months ended March 31, 2016. For Exelon and Generation, assumed operational controlincludes the operations of CENG’s nuclear fleet. As a result, beginning April 1, 2014, the financial results include CENG’s resultsPHI acquired businesses for the period of operations on a fully consolidated basis.March 24, 2016, through March 31, 2016.

   Successor  Predecessor 
   March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
   Three
Months
Ended
March 31,
2015
 

PHI

  $(309 $19    $53  

Results of Operations — Generation

 

 Three Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
   Three Months Ended
March 31,
 Favorable
(Unfavorable)
Variance
 
 2015 2014 2015 2014(a)       2016         2015     

Operating revenues

 $4,768   $4,412   $356   $14,841   $12,591   $2,250    $4,739   $5,840   $(1,101

Purchased power and fuel expense

  2,519    1,880    (639  7,800    7,071    (729   2,442    3,433    991  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Revenue net of purchased power and fuel(b)(a)

  2,249    2,532    (283  7,041    5,520    1,521     2,297    2,407    (110

Other operating expenses

          

Operating and maintenance

  1,241    1,266    25    3,860    3,765    (95   1,467    1,311    (156

Depreciation and amortization

  264    253    (11  774    719    (55   289    254    (35

Taxes other than income

  123    127    4    369    350    (19   126    122    (4
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other operating expenses

  1,628    1,646    18    5,003    4,834    (169   1,882    1,687    (195
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Equity in earnings (losses) of unconsolidated affiliates

      1    (1      (20  20  

Gain on sales of assets

  1    338    (337  7    355    (348

Gain on consolidation and acquisition of businesses

                  261    (261

Loss on sales of assets

       (1  1  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Operating income

  622    1,225    (603  2,045    1,282    763     415    719    (304
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other income and (deductions)

          

Interest expense

  (68  (89  21    (269  (261  (8   (97  (102  5  

Other, net

  (257  4    (261  (193  306    (499   93    94    (1
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other income and (deductions)

  (325  (85  (240  (462  45    (507   (4  (8  4  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Income before income taxes

  297    1,140    (843  1,583    1,327    256     411    711    (300

Income taxes (benefit)

  (36  291    327    371    290    (81

Income taxes

   151    226    75  

Equity in losses of unconsolidated affiliates

  (1      (1  (4      (4   (3      3  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Net income

  332    849    (517  1,208    1,037    171     257    485    (228

Net income (loss) attributable to noncontrolling interests

  (45  78    123    (10  111    121  

Net (loss) income attributable to noncontrolling interests

   (53  42    95  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Net income attributable to membership interest

 $377   $771   $(394 $1,218   $926   $292    $310   $443   $(133
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, the financial results include CENG’s results of operations on a fully consolidated basis.

(b)

Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Net Income Attributable to Membership Interest

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    Generation’s net income attributable to membership interest for the three months ended September 30, 2015March 31, 2016 decreased compared to the same period in 20142015, primarily due to lower revenue net of purchased power and fuel expense, lower gains on sales of assets and decreased other income, partially offset by decreasedhigher operating and maintenance expense and income taxhigher depreciation and amortization expense. The decrease in revenue net of purchased power and fuel expense primarily relates to mark-to-market losses in 2015 compared tothe lower realized energy prices, lower mark-to-market gains in 20142016 compared to 2015, decrease in amortization of contracts recorded at fair value associated with prior acquisitions, and lower margins and capacity revenues resulting from the absence of generating units soldhigher oil inventory write downs in 2014,2016 versus 2015, partially offset by the benefit of lower cost to serve load, the inclusion of Integrys’ results in 2015,nuclear refueling outage timing, fewer non-refueling outage days and increased load served.capacity prices. The decreaseincrease in gains on salesof assets is primarily due to the absence in 2015 of the gain on sale of Safe Harbor Water Power Corporation recorded in 2014. The decrease in other income is primarily due to the change in realized and unrealized gains and losses on NDT funds. The decrease in operating

and maintenance expense is primarily related to a reductionUpstream asset impairment in merger and integration costs in 2015 and the absence of impairment charges for certain generating assets held for sale recorded in 2014, partially offset by increased contracting costs primarily due to growth development projects at Generation. The decrease in income taxes is primarily due to the absence of the gain on the sale of Safe Harbor Water Power Corporation recorded in 2014 and an increase in the domestic production activities deduction.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.     Generation’s net income attributable to membership interest for the nine months ended September 30, 2015 increased compared to the same period in 2014 primarily due to higher revenue net of purchased power and fuel expense, partially offset by an increase in operating and maintenance expense, decreased gains on sales of assets, the 2014 gain recognized as a result of the consolidation of CENG, decreased other income and increased income taxes.2016. The increase in revenue net of purchased powerdepreciation and fuel expense relates to the inclusion of CENG’s results on a fully consolidated basis in 2015, a reduction in the number of nuclear outage days in 2015, the inclusion of Integrys’ results in 2015, the benefit of lower cost to serve load (which includes the absence of higher procurement costs for replacement power due to extreme cold weather in the first quarter of 2014), the cancellation of the DOE spent nuclear fuel disposal fee, increased capacity prices, favorability from portfolio management optimization activities, increased load served and mark-to-market gains in 2015 compared to mark-to-market losses in 2014, partially offset by lower margins and capacity revenues resulting from the 2014 sales of generating assets, lower realized energy prices and the absence of fuel optimization opportunities realized in 2014 in the South. The increase in operating and maintenanceamortization expense is primarily related to the inclusion of CENG’s results on a fully consolidated basisincreased nuclear decommissioning amortization and ongoing capital expenditures in 2015, partially offset by the absence of impairment charges for wind generating assets and certain assets held for sale recorded in 2014. The decrease in gains on sales of assets is primarily due to the absence in 2015 of the gain on sale of Safe Harbor Water Power Corporation in 2014. The decrease in other income is primarily due to the change in realized and unrealized gains and losses on NDT funds. The increase in income taxes is primarily due to mark-to-market gains recorded in 2015 compared to market-to-market losses recorded in 2014, partially offset by the gain on the consolidation of CENG in 2014 and an increase in the domestic production activities deduction.2016.

Revenue Net of Purchased Power and Fuel Expense

The basis for Generation’s reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels

(wholesale (wholesale and retail). Generation’s hedging strategies and risk metrics are also aligned with these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:

 

  

Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

 

  

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

 

  

New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

 

  

New York represents operations within ISO-NY, which covers the state of New York in its entirety.

 

  

ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

 

  

Other Power Regions:

 

  

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

 

  

West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

 

  

Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

The following business activities are not allocated to a region, and are reported in the table below inunder Other: natural gas, as well as other miscellaneous business activities that are not significant to Generation’s overall operating revenues or results of operations. Further, the following activities are not allocated to a region, and are reported in the table below in Other: unrealized mark-to-market impact of economic hedging activities,activities; amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitionsacquisitions; and other miscellaneous revenues.

Generation evaluates the operating performance of its power marketing activities using the measure of revenue net of purchased power and fuel expense which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to ComEd, PECO and BGE.the Utility Registrants. Purchased power costs

include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

For the three and nine months ended September 30,March 31, 2016 and 2015, and 2014, Generation’s revenue net of purchased power and fuel expense by region were as follows:

 

   Three Months Ended
September 30,
   Variance  % Change 
       2015          2014        

Mid-Atlantic(b)

  $991   $935    $56    6.0

Midwest(c)

   752    716     36    5.0

New England

   133    90     43    47.8

New York

   167    186     (19  (10.2)% 

ERCOT

   111    109     2    1.8

Other Power Regions(d)

   83    68     15    22.1
  

 

 

  

 

 

   

 

 

  

 

 

 

Total electric revenue net of purchased power and fuel expense

   2,237    2,104     133    6.3

Proprietary trading

       23     (23  (100.0)% 

Mark-to-market gains (losses)

   (139  267     (406  (152.1)% 

Other(e)

   151    138     13    9.4
  

 

 

  

 

 

   

 

 

  

 

 

 

Total revenue net of purchased power and fuel expense

  $2,249   $2,532    $(283  (11.2)% 
  

 

 

  

 

 

   

 

 

  

 

 

 

  Nine Months Ended
September 30,
 Variance  % Change   Three Months Ended
March 31,
   Variance  % Change 
      2015           2014           2016           2015        

Mid-Atlantic(f)(a)

  $2,663    $2,550   $113    4.4  $841    $787    $54    6.9

Midwest(c)(b)

   2,195     1,877    318    16.9   718     703     15    2.1

New England

   379     290    89    30.7   81     158     (77  (48.7)% 

New York(f)

   498     313    185    59.1   130     189     (59  (31.2)% 

ERCOT

   235     250    (15  (6.0)%    61     55     6    10.9

Other Power Regions(d)

   193     249    (56  (22.5)%    76     46     30    65.2
  

 

   

 

  

 

  

 

   

 

   

 

   

 

  

 

 

Total electric revenue net of purchased power and fuel expense

   6,163     5,529    634    11.5   1,907     1,938     (31  (1.6)% 

Proprietary trading

   3     43    (40  (93.0)% 

Proprietary Trading

   3     4     (1  (25.0)% 

Mark-to-market gains (losses)

   258     (477  735    154.1   103     162     (59  (36.4)% 

Other(e)(c)

   617     425    192    45.2   284     303     (19  (6.3)% 
  

 

   

 

  

 

  

 

   

 

   

 

   

 

  

 

 

Total revenue net of purchased power and fuel expense

  $7,041    $5,520   $1,521    27.6  $2,297    $2,407    $(110  (4.6)% 
  

 

   

 

  

 

  

 

   

 

   

 

   

 

  

 

 

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning April 1, 2014, the financial results include CENG’s results on a fully consolidated basis.

(b)

Results of transactions with PECO and BGE are included in the Mid-Atlantic region. As a result of the PHI Merger, for the Successor period of March 24, 2016 to March 31, 2016, results of transactions with Pepco, DPL and ACE are included in the Mid-Atlantic region.

(c)(b)

Results of transactions with ComEd are included in the Midwest region.

(d)

Other Power Regions includes South, West and Canada.

(e)(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $4 million decrease to RNF and a $20 million increase to RNF for the amortization of intangible assets related to commodity contracts recorded at fair value of $19 million and $38 million increase to revenue net of purchased power and fuel expense for the three and nine months ended September 30,March 31, 2016 and 2015, respectively, and $15 million increase to RNF and $78 million decrease to RNF for the amortization of intangible assets related to commodity contracts for the three and nine months ended September 30, 2014, respectively.

(f)

Includes $113 million and $169 million of purchased power from CENG prior to its consolidation on April 1, 2014 in the Mid-Atlantic and New York regions, respectively, for the nine months ended September 30, 2014.

Generation’s supply sources by region are summarized below:

 

   Three Months Ended
September 30,
   Variance  % Change 

Supply Source (GWh)

  2015   2014    

Nuclear Generation

       

Mid-Atlantic(a)

   16,446     15,993     453    2.8

Midwest

   23,927     24,379     (452  (1.9)% 

New York(a)

   4,807     4,891     (84  (1.7)% 
  

 

 

   

 

 

   

 

 

  

 

 

 

Total Nuclear Generation

   45,180     45,263     (83  (0.2)% 

Fossil and Renewables(a)

       

Mid-Atlantic

   719     2,385     (1,666  (69.9)% 

Midwest

   262     212     50    23.6

New England

   1,840     1,789     51    2.9

New York

   1     1         

ERCOT

   2,306     2,331     (25  (1.1)% 

Other Power Regions(c)

   1,945     2,285     (340  (14.9)% 
  

 

 

   

 

 

   

 

 

  

 

 

 

Total Fossil and Renewables

   7,073     9,003     (1,930  (21.4)% 

Purchased Power

       

Mid-Atlantic

   3,511     1,110     2,401    n.m.  

Midwest

   515     260     255    98.1

New England

   5,787     3,231     2,556    79.1

ERCOT

   2,422     2,184     238    10.9

Other Power Regions(c)

   5,189     4,397     792    18.0
  

 

 

   

 

 

   

 

 

  

 

 

 

Total Purchased Power

   17,424     11,182     6,242    55.8

Total Supply/Sales by Region(d)

       

Mid-Atlantic(e)

   20,676     19,488     1,188    6.1

Midwest(e)

   24,704     24,851     (147  (0.6)% 

New England

   7,627     5,020     2,607    51.9

New York

   4,808     4,892     (84  (1.7)% 

ERCOT

   4,728     4,515     213    4.7

Other Power Regions(c)

   7,134     6,682     452    6.8
  

 

 

   

 

 

   

 

 

  

 

 

 

Total Supply/Sales by Region

   69,677     65,448     4,229    6.5
  

 

 

   

 

 

   

 

 

  

 

 

 

  Nine Months Ended
September 30,
   Variance  % Change   Three Months Ended
March 31,
   Variance  % Change 

Supply Source (GWh)

  2015   2014    

Nuclear Generation

       

Supply source (GWh)

      2016           2015       Variance  % Change 

Nuclear generation

       

Mid-Atlantic(a)

   47,783     43,042     4,741    11.0   16,208     15,718     490    3.1

Midwest

   69,802     70,223     (421  (0.6)%    23,662     22,427     1,235    5.5

New York(a)

   14,057     8,657     5,400    62.4   4,932     4,512     420    9.3
  

 

   

 

   

 

  

 

   

 

   

 

   

 

  

 

 

Total Nuclear Generation

   131,642     121,922     9,720    8.0   44,802     42,657     2,145    5.0

Fossil and Renewables(a)

              

Mid-Atlantic

   2,028     8,758     (6,730  (76.8)%    898     559     339    60.6

Midwest

   1,057     948     109    11.5   449     432     17    3.9

New England

   2,575     4,822     (2,247  (46.6)%    1,924     600     1,324    n.m.  

New York

   3     3            1     1         

ERCOT

   4,600     5,541     (941  (17.0)%    1,376     1,422     (46  (3.2)% 

Other Power Regions(c)

   6,014     5,954     60    1.0

Other Power Regions

   2,147     1,973     174    8.8
  

 

   

 

   

 

  

 

   

 

   

 

   

 

  

 

 

Total Fossil and Renewables

   16,277     26,026     (9,749  (37.5)%    6,795     4,987     1,808  �� 36.3

Purchased Power

              

Mid-Atlantic(b)

   6,719     5,152     1,567    30.4

Mid-Atlantic

   3,755     1,824     1,931    105.9

Midwest

   1,511     1,491     20    1.3   706     589     117    19.9

New England

   17,937     7,591     10,346    136.3   4,155     6,408     (2,253  (35.2)% 

New York(b)

        2,857     (2,857  (100.0)% 

ERCOT

   7,569     6,685     884    13.2   2,294     2,244     50    2.2

Other Power Regions(c)

   12,666     11,406     1,260    11.0

Other Power Regions

   2,600     3,758     (1,158  (30.8)% 
  

 

   

 

   

 

  

 

   

 

   

 

   

 

  

 

 

Total Purchased Power

   46,402     35,182     11,220    31.9   13,510     14,823     (1,313  (8.9)% 

Total Supply/Sales by Region(d)

       

Mid-Atlantic(e)

   56,530     56,952     (422  (0.7)% 

Midwest(e)

   72,370     72,662     (292  (0.4)% 

Total Supply/Sales by Region(b)

       

Mid-Atlantic(c)

   20,861     18,101     2,760    15.2

Midwest(c)

   24,817     23,448     1,369    5.8

New England

   20,512     12,413     8,099    65.2   6,079     7,008     (929  (13.3)% 

New York

   14,060     11,517     2,543    22.1   4,933     4,513     420    9.3

ERCOT

   12,169     12,226     (57  (0.5)%    3,670     3,666     4    0.1

Other Power Regions(c)

   18,680     17,360     1,320    7.6

Other Power Regions

   4,747     5,731     (984  (17.2)% 
  

 

   

 

   

 

  

 

   

 

   

 

   

 

  

 

 

Total Supply/Sales by Region

   194,321     183,130     11,191    6.1   65,107     62,467     2,640    4.2
  

 

   

 

   

 

  

 

   

 

   

 

   

 

  

 

(a)

Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). Nuclear generation for the three and nine months ended September 30, 2015 includes physical volumes of 3,808 GWh and 10,835 GWh in the Mid-Atlantic region and 4,807 GWh and 14,057 GWh in the New York region for CENG. Nuclear generation for the three and nine months ended September 30, 2014 includes physical volumes of 3,726 GWh and 7,507 GWh in the Mid-Atlantic region and 4,891 GWh and 8,657 GWh in the New York region for CENG. Prior to the integration date of April 1, 2014, CENG volumes were included in purchased power.

(b)

Purchased power for the nine months ended September 30, 2014 includes physical volumes of 2,489 GWh in the Mid-Atlantic and 2,857 GWh in the New York regions as a result of the PPA with CENG. As of the integration date of April 1, 2014, CENG volumes are included in nuclear generation.

(c)

Other Power Regions includes South, West and Canada.

(d)

Excludes physical proprietary trading volumes of 1,9131,220 GWh and 3,0061,808 GWh for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, and 5,378 GWh and 8,129 GWh for nine months ended September 30, 2015 and 2014, respectively.

(e)(c)

Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the merger, for the Successor period of March 24, 2016 to March 31, 2016, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region.

Mid-Atlantic

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $56$54 million increase in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to thebenefit of lower cost to serve load,reflects nuclear refueling outage timing, fewer non-refueling outage days and higher capacity revenues and increased load volumes served, higher nuclear volumes, and higher capacity revenues, partially offset by lower generation volumes due to the sale of various generating assets.higher oil inventory write-downs in 2016.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $113 million increase in revenue net of purchased power and fuel expense in the Mid-Atlantic was primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015, benefit of lower cost to serve load (which includes the absence of higher procurement costs for replacement power due to extreme cold weather in the first quarter of 2014), increased load volumes served, higher nuclear volumes, the cancellation of the DOE spent nuclear fuel disposal fee, and favorability from portfolio management optimization activities, partially offset by lower capacity revenues, and lower generation volumes due to the sale of generating assets.

Midwest

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $36$15 million increase in revenue net of purchased power and fuel expense in the Midwest was primarily due to the benefit of lower cost to serve load, increased load volumes served, the inclusion of Integrys’ results in 2015,reflects nuclear refuelingoutage timing, fewer non-refueling outage days and higher capacity revenues, partially offset by lower nuclear volumes.realized energy prices.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $318 million increase in revenue net of purchased power and fuel expense in the Midwest was primarily due to higher capacity revenues, the benefit of lower cost to serve load, increased load volumes served, the inclusion of Integrys’ results in 2015, the cancellation of the DOE spent nuclear fuel disposal fee, and favorability from portfolio management optimization activities, partially offset by lower nuclear volumes.

New England

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $43$77 million increasedecrease in revenue net of purchased power and fuel expense in New England was primarily due to the benefit ofdriven by lower cost to serve load, increased load volumes served,realized energy prices, higher oil inventory write-downs in 2016, and the inclusion of Integrys’ results in 2015, partially offset by lower generation volumes due to the sale of a generating asset.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $89 million increase in revenue net of purchasedfrom power and fuel expense in New England was primarily due to the benefit of lower cost to serve load, increased load volumes served and the inclusion of Integrys’ results in 2015, partially offset by lower generation volumes due to the sale of a generating asset.purchase agreements.

New York

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $19$59 million decrease in revenue net of purchased power and fuel expense in New York was primarily due to lower capacity revenues, lower realized energy prices, lower capacity revenues, and lower nuclear volumes.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $185 million increase in revenue netthe amortization of purchased power and fuel expense in New York was primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015 and higher nuclear volumes,contracts recorded at fair value associated with prior acquisitions, partially offset by lower realized energy pricesnuclear refueling outage timing and lower capacity revenues.fewer non-refueling outage days.

ERCOT

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.    March 31, 2015.The $2$6 million increase in revenue net of purchased power and fuel expense in ERCOT was primarily due to lower fuel costs,higher generation volumes from renewable facilities and the amortization of contracts recorded at fair value associated with prior acquisitions, partially offset by lower realized energy prices.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $15 million decrease in revenue net of purchased power and fuel expense in ERCOT was primarily due to lower realized energy prices and lower generation volumes due to the sale of a generating asset, partially offset by the absence of higher procurement costs for replacement power in 2014 and lower fuel costs.from fossil facilities.

Other Power Regions

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $15$30 million increase in revenue net of purchased power and fuel expense in Other Power Regions was primarily due to the amortization of contracts recorded at fair value associated with prior acquisitions, and higher generation volumes from power purchase agreements and lower fuel costs, partially offset by lower realized energy prices.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $56 million decrease in revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices and the absence of the 2014 fuel optimization opportunities, partially offset by higher generation volumes from power purchase agreements and lower fuel costs.volumes.

Proprietary tradingTrading

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $23$1 million decrease in revenue net of purchased power and fuel expense in Proprietary tradingTrading was primarily due to the absence of gains ondecreased congestion trading products.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $40 million decrease in revenue net of purchased power and fuel expense in Proprietary trading was primarily due to the absence of gains on congestion trading products.activity.

Mark-to-market

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.    Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market losses on economic hedging activities were $139 million for the three months ended September 30, 2015 compared to gains of $267 million for the three months ended September 30, 2014. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.March 31, 2015.    Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to mitigate exposure to these fluctuations. Mark-to-market gains on economic hedging activities were $258$103 million for the ninethree months ended September 30, 2015March 31, 2016 compared to lossesgains of $477$162 million for the ninethree months ended September 30, 2014.March 31, 2015. See Notes 98 — Fair Value of Financial Assets and Liabilities and 109 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

Other

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The $13$19 million increasedecrease in other revenue net of purchased power and fuel expense was primarily driven bydue to the amortization of energy contracts recorded at fair value duringassociated with prior acquisitions and the addition of Integrys.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The $192 milliondecreased gas sales, partially offset by an increase in other revenue net of purchased powerdistributed generation and fuel expense was primarily driven by the amortization of contracts recorded at fair value during prior acquisitions, and the addition of Integrys.energy efficiency activity.

Nuclear Fleet Capacity Factor and Production Costs

The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2015March 31, 2016 as compared to the same periodsperiod in 2014,2015, for the Generation-operated plants. Theplants.The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Nuclear fleet production cost is defined as the costs to produce one MWh of energy, including fuel, materials, labor, contracting and other miscellaneous costs, but excludes depreciation, required capital investment, benefits costs associated with labor, insurance, property taxes, unit contingent costs, suspended DOE nuclear waste storage fees, and certain other non-production related overhead costs. Generation considers capacity factor and production coststo be a useful measures comparativelymeasure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

 

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   2015  2014  2015  2014 

Nuclear fleet capacity factor(a)

   95.5  96.5  93.8  94.1

Nuclear fleet production cost per MWh(a)

  $18.26   $17.99   $19.44   $19.58  
    Three Months Ended
March 31,
 
    2016  2015 

Nuclear fleet capacity factor(a)

   95.8  92.7

 

(a)

Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet, and as a result, beginning on April 1, 2014, the financial results include CENG’s results of operations on a fully consolidated basis.

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    The nuclear fleet capacity factor which excludes Salem, decreasedincreased primarily due to a higher number ofnuclear refueling outage timing and fewer non-refueling outage days, excluding Salem outages, days during the three months ended September 30, 2015March 31, 2016 compared to the same period in 2014, partially offset by a lower number of non-refueling outage days.2015. For the three months ended September 30,March 31, 2016 and 2015, and 2014,planned refueling outage days totaled 2770 and 18,89, respectively. During the same periods, non-refueling outage days totaled 1110 and 20,32, respectively. Production costs per MWh were higher for the three months ended September 30, 2015 as compared to the same period in 2014 due to a lower fleet capacity factor.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The nuclear fleet capacity factor, which excludes Salem, decreased primarily due to a higher number of refueling outage days and non-outage energy losses during the nine months ended September 30, 2015 compared to the same period in 2014, partially offset by a lower number of unplanned outage days. For the nine months ended September 30, 2015 and 2014, refueling outage days totaled 187 (of which 51 were related to CENG plants) and 178 (of which 52 were related to CENG plants), respectively. During the same periods, non-refueling outage days totaled 61 (of which 12 were related to CENG) and 84 (of which 5 were related to CENG), respectively. Production costs per MWh were lower for the nine months ended September 30, 2015 as compared to the same period in 2014, due to the elimination of the spent nuclear fuel disposal fee in 2014, partially offset by the inclusion of CENG.

Operating and Maintenance

The changes in operating and maintenance expense for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 2014,2015, consisted of the following:

 

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   Increase
(Decrease)
  Increase
(Decrease)(a)
 

Labor, other benefits, contracting, materials

  $45   $202  

Corporate allocations(b)

   6    17  

Materials and supplies related expenses

   10    10  

Asset retirement obligation update(c)

   8    8  

Pension and non-pension postretirement benefits expense

   6    10  

Nuclear refueling outage costs, including the co-owned Salem plants

   2    8  

Regulatory fees and assessment

   2    12  

Midwest Generation bankruptcy recoveries

       (14

Accretion expense(d)

   (2  21  

Merger and integration costs

   (46  (56

Impairment of long-lived assets(e)

   (47  (135

Other

   (9  12  
  

 

 

  

 

 

 

Increase (decrease) in operating and maintenance expense

  $(25 $95  
  

 

 

  

 

 

 
    Increase (Decrease) 

Labor, other benefits, contracting, materials

  $7  

Nuclear refueling outage costs, including the co-owned Salem plants

   (7

Corporate allocations

   (1

Allowance for uncollectible accounts

   2  

Merger and integration costs(a)

   15  

Merger commitments

   3  

Pension and non-pension postretirement benefits expense

   (11

Impairment of long-lived assets(b)

   119  

Cost management program(c)

   18  

Other

   11  
  

 

 

 

Increase in operating and maintenance expense

  $156  
  

 

 

 

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014,Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, upfront credit facilities fees, and certain pre-acquisition contingencies, and the financial results include CENG’s results of operations on a fully consolidated basis.PHI acquisition.

(b)

Reflects an increased sharePrimarily relates to the impairment of corporate allocated costs.Upstream assets in 2016.

(c)

ReflectsRepresents the impact of the annual update of Generation’s nuclear decommissioning obligation for Non-Regulatory Agreement Units.

(d)

Includes the elimination of activity for the Regulatory Agreement Units, including the elimination of revenueseverance expense and depreciation for those units. See Note 15—Asset Retirement Obligations of the Exelon 2014 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(e)

Reflects the impact of a 2014 charge to earningsreorganization costs related to the impairment of wind generating assets and certain generation assets held for sale.a cost management program in 2016

Depreciation and Amortization

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014.    Depreciation and amortization expense for the three months ended September 30, 2015 compared to the three months ended September 30, 2014 remained relatively consistent.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The increase in depreciation and amortization expense for the ninethree months ended September 30, 2015March 31, 2016 compared to the ninethree months ended September 30, 2014March 31, 2015 is primarily due the inclusion of CENG’s results on a fully consolidated basis in 2015.to increased nuclear decommissioning amortization and ongoing capital expenditures.

Taxes Other Than Income

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014.    Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three months ended September 30, 2015March 31, 2016 compared to the three months ended September 30, 2014March 31, 2015 remained relatively level.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. The increase in taxes other than income for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 is primarily due the inclusion of CENG’s results on a fully consolidated basis in 2015.

Equity in Losses of Unconsolidated Affiliates

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014.    Equity in losses of unconsolidated affiliates for the three months ended September 30, 2015 compared to the three months ended September 30, 2014 remained relatively consistent.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The decrease in equity in losses of unconsolidated affiliates for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 is primarily due to CENG’s operating results being fully consolidated beginning April 1, 2014 and, as a result, are not reflected as equity method losses in 2015.stable.

Gain on Sales of Assets

The unfavorable change in gain on sales of assets for the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 is primarily due to the gain on sale of Safe Harbor Water Power Corporation, which was recorded in 2014.

Interest Expense

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014.    The decrease in interestInterest expense for the three months ended September 30, 2015March 31, 2016 compared to the three months ended September 30, 2014 is primarily related to the favorable settlement inMarch 31, 2015 of an income tax position on Constellation’s pre-acquisition tax returns, partially offset by increased interest expense due to higher outstanding debt.remained relatively stable.

Other, Net

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    The increase in interest expenseOther, net for the three months ended September 30, 2015March 31, 2016 compared to the three months ended September 30, 2014 is primarily related to higher outstanding debt, partially offset by the favorable settlement inMarch 31, 2015 of an income tax position on Constellation’s pre-acquisition tax returns.

Other, Net

The decrease inremained relatively stable. Other, net for the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 primarily reflects the change in the realized and unrealized gains and losses related to the NDT funds of its Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $(55)$20 million and $(16)$23 million for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, and $(44) million and $50 million for the nine months ended September 30, 2015 and 2014, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 1312 — Nuclear Decommissioning of the Combined Notes to the Consolidated Financial Statements for additional information regarding NDT funds. For the three and nine months ended September 30, 2015, the change in Other, net also included a benefit recorded in 2014 for the favorable settlement of certain income tax positions on Constellation’s pre-acquisition tax returns.

The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and nine months ended September 30, 2015March 31, 2016 and 2014:2015:

 

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
     2015      2014      2015(a)      2014   

Net unrealized gains (losses) on decommissioning trust funds

  $(218 $(41 $(274 $100  

Net realized gains (losses) on sale of decommissioning trust funds

   (3  17    53    42  
    Three Months Ended
March 31,
 
    2016   2015 

Net unrealized gains on decommissioning trust funds

  $52    $40  

Net realized gains on sale of decommissioning trust funds

   3     6  

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 financial results include CENG’s results of operations on a fully consolidated basis.

Equity in Losses of Unconsolidated Affiliates

Equity in losses of unconsolidated affiliates for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 remained relatively stable.

Effective Income Tax Rate

TheGeneration’s effective income tax rate was (12.1)%36.7% and 23.4%31.8% for the three and nine months ended September 30,March 31, 2016 and 2015, respectively, compared to 25.5% and 21.9% for the same periods during 2014.respectively. See Note 1211 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

Results of Operations — ComEd

 

 Three Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
   Three Months Ended
March 31,
 Favorable
(Unfavorable)
Variance
 
 2015 2014 2015 2014       2016         2015     

Operating revenue

 $1,376   $1,222   $154   $3,709   $3,484   $225  

Operating revenues

  $1,249   $1,185   $64  

Purchased power expense

  390    326    (64  991    915    (76   348    327    (21
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Revenue net of purchased power expense(a)(b)

  986    896    90    2,718    2,569    149     901    858    43  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other operating expenses

          

Operating and maintenance

  404    359    (45  1,166    1,040    (126   368    378    10  

Depreciation and amortization

  176    174    (2  528    521    (7   189    175    (14

Taxes other than income

  79    76    (3  225    225         75    75      
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other operating expenses

  659    609    (50  1,919    1,786    (133   632    628    (4
  

 

  

 

  

 

 

Gain on sales of assets

   5        5  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Operating income

  327    287    40    799    783    16     274    230    44  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other income and (deductions)

          

Interest expense, net

  (83  (81  (2  (248  (241  (7   (86  (84  (2

Other, net

  4    4        14    14         4    3    1  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other income and (deductions)

  (79  (77  (2  (234  (227  (7   (82  (81  (1
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Income before income taxes

  248    210    38    565    556    9     192    149    43  

Income taxes

  99    84    (15  226    221    (5   77    59    (18
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Net income

 $149   $126   $23   $339   $335   $4    $115   $90   $25  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

 

(a)

ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

(b)

For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

Net Income

Three Months Ended September 30, 2015months ended March 31, 2016 Compared to Three Months Ended September 30, 2014.months ended March 31, 2015.    ComEd’s net income for the three months ended September 30, 2015March 31, 2016 was higher than the same period in 2014, primarily due to favorable weather and increased electric distribution and transmission formula rate revenues (reflecting the impacts of increased capital investment, partially offset by lower allowed electric distribution ROE).

Nine Months Ended September 30, 2015, Compared to Nine Months Ended September 30, 2014.    ComEd’s net income for the nine months ended September 30, 2015 was higher than the same period in 2014, primarily due to increased electric distribution and transmission formula rate revenuesearnings (reflecting the impacts of increased capital investment,investment), partially offset by lower allowed ROE).unfavorable weather.

Operating Revenue Net of Purchased Power Expense

There are certain drivers of Operating revenue that are fully offset by their impact on Purchased power expense, such as commodity procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retail customers without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on revenueRevenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 20142015 Form 10-K for additional information on ComEd’s electricity procurement process.

All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenue related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.

Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2015,March 31, 2016, compared to the same period in 2014,2015, consisted of the following:

 

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   2015  2014  2015  2014 

Electric

   75  79  77  80
    Three Months Ended
March 31,
 
    2016  2015 

Electric

   73  78

Retail customers purchasing electric generation from competitive electric generation suppliers at September 30,March 31, 2016 and 2015 and 2014 consisted of the following:

 

   September 30, 2015  September 30, 2014 
   Number of
customers
   % of total retail
customers
  Number of
customers
   % of total retail
customers
 

Electric

   1,664,600     43  2,422,900     63
    March 31, 2016  March 31, 2015 
    Number of
customers
   % of total retail
customers
  Number of
customers
   % of total retail
customers
 

Electric

   1,649,700     42  2,406,300     62

TheUnder an Illinois law allowing municipalities to arrange the purchase of electricity for their participating residents, the City of Chicago previously participated in ComEd’s customer choice program and purchasedarranged the purchase of electricity from Constellation (formerly Integrys). As of, for those participating residents. In September 2015, the City of Chicago no longer participatesdiscontinued its participation in the customer choice program and began purchasing itsmany of those participating residents resumed their purchase of electricity from ComEd. It is anticipated that by the end of the fourth quarter 2015 approximately 43% of retail customers and 72% of kWh sales in the ComEd service territory will be supplied by competitive retail electric suppliers, reflecting the City of Chicago switching back to ComEd. ComEd’s Operating revenue has increased as a result of the City of Chicago switching, but that increase is fully offset in Purchased power expense.

The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2015,March 31, 2016, compared to the same periodsperiod in 20142015 consisted of the following:

 

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   Increase (Decrease)  Increase (Decrease) 

Weather

  $17   $(2

Volume

   (1  (14

Electric distribution revenue

   36    80  

Transmission revenue

   11    24  

Regulatory required programs

   21    2  

Uncollectible accounts recovery, net

   (6  37  

Pricing and customer mix

   12    13  

Revenue subject to refund

       9  
  

 

 

  

 

 

 

Increase in revenue net of purchased power expense

  $90   $149  
  

 

 

  

 

 

 

    Increase (Decrease) 

Weather

  $(20

Volume

   (4

Electric distribution revenue

   44  

Transmission revenue

   37  

Regulatory required programs

   (18

Uncollectible accounts recovery, net

   (13

Pricing and customer mix

   11  

Other

   6  
  

 

 

 

Total increase (decrease)

  $43  
  

 

 

 

Weather.    The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage. Conversely, mild weather reduces demand. For the three monthsthreemonths ended September 30, 2015, favorable weather conditions increased Operating revenue net of purchased power expense when compared to the same period in 2014.

For the nine months ended September 30, 2015,March 31, 2016, unfavorable weather conditions reduced Operating revenue net of purchased power expense when compared to the same period in 2014.2015.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd’s service territory with cooling degree days generally having a more

significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30,March 31, 2016, and 2015, and 2014, consisted of the following:

 

  Three Months Ended
March 31,
       % Change

Heating and Cooling Degree-Days

              % Change       2016           2015       Normal   2016 vs. 2015  2016 vs. Normal

Three Months Ended September 30,

  2015   2014   Normal   From 2014 From Normal 

Heating Degree-Days

   55     111     119     (50.5)%   (53.8)%    2,900     3,632     3,164    (20.2)%  (8.3)%

Cooling Degree-Days

   634     537     613     18.1  3.4                 n/a  n/a

Nine Months Ended September 30,

                  

Heating Degree-Days

   4,373     4,680     4,048     (6.6)%   8.0

Cooling Degree-Days

   805     796     831     1.1  (3.1)% 

Volume.    Revenue net of purchased power expense decreased as a result of lower delivery volume, exclusive of the effects of weather, reflecting decreased average usage per residential customer, primarily due to the impacts of energy efficiency programs, as compared to the same three and nine months periodsmonth period in 2014.2015.

Electric Distribution Revenue.    EIMA provides for a performance-based formula rate formula,tariff, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under EIMA, electric distribution revenue varies from year to year based onupon fluctuations in the underlying costs, investments being recovered, allowed ROE, and other billing determinants. ComEd’s allowed ROE is the annual average rate ofon 30-year treasury notes plus 580 basis points, subject to a collar of plus or minus 50 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. During the three and nine months ended September 30, 2015,March 31, 2016, ComEd recorded increased electric distribution revenue primarily due to increased capital investment partially offset by lower allowed ROE due to a decrease in treasury rates.and higher Operating and maintenance and Depreciation and amortization expense. See Operating and Maintenance Expensemaintenance expense and Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s rate formula pursuant to EIMA.information.

Transmission Revenue.    Under a FERC-approved formula, transmission revenue varies from year to year based onupon fluctuations in the underlying costs, investments being recovered and other billing determinants, such as the highest daily peak load from the previous calendar year. For the three and nine months ended September 30, 2015,March 31, 2016, ComEd recorded increased transmission revenue primarily due to increased capital investment.investment and an increase in the highest daily peak load. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs.    This represents the change in Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as ComEd’s energy efficiency and demand response and purchased power administrative costs. The riders are designed to provide full and current cost recovery. An equal and offsetting amount has been included in Operating and maintenance expense. Refer to theSee Operating and maintenance expense discussion below for additional information on included programs.

Uncollectible Accounts Recovery, Net.    Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See the Operating and maintenance expense discussion below for additional information on this tariff.

Pricing and Customer Mix.    The increase in Revenue net of purchased power as a result of pricing and customer mix is primarily attributable to higher overall effective rates due to decreased usage across all major customer classes and change in customer mix for the three and nine months ended September 30, 2015,March 31, 2016, as compared to the same periodsperiod in 2014.2015.

Revenue SubjectOther.    Other revenue, which can vary period to Refund.    ComEd recordsperiod, includes rental revenue, subjectrevenue related to refund based upon its best estimatelate payment charges, assistance provided to other utilities through mutual assistance programs, recoveries of customer collections that may be required to be refunded. Revenue net of purchase power was higher for the nine months ended September 30, 2015 due to the one-time revenue refundenvironmental costs associated with Rider AMP recorded in the second quarterMGP sites, and recoveries of 2014. See Note 3—Regulatory Matters of the Exelon 2014 Form 10-K for additional information regarding Rider AMP.energy procurement costs.

Operating and Maintenance Expense

 

 Three Months Ended
September 30,
 Increase  Nine Months Ended
September 30,
 Increase   Three Months Ended
March 31,
   Increase
(Decrease)
 
     2015         2014         2015         2014           2016           2015       

Operating and maintenance expense — baseline

 $338   $314   $24   $1,005   $881   $124    $331    $323    $8  

Operating and maintenance expense — regulatory required programs(a)

  66    45    21    161    159    2     37     55     (18
 

 

  

 

  

 

  

 

  

 

  

 

   

 

   

 

   

 

 

Total operating and maintenance expense

 $404   $359   $45   $1,166   $1,040   $126    $368    $378    $(10
 

 

  

 

  

 

  

 

  

 

  

 

   

 

   

 

   

 

 

 

(a)

Operating and maintenance expensesexpense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operatingOperating revenue.

The changes in operatingOperating and maintenance expense for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 2014,2015, consisted of the following:

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
 
  Increase
(Decrease)
 Increase   Increase (Decrease) 

Baseline

     

Labor, other benefits, contracting and materials(a)

  $2   $38  

Pension and non-pension postretirement benefits expense

   9    8  

Labor, other benefits, contracting and materials

  $1  

Pension and non-pension postretirement benefits expense(a)

   (5

Storm-related costs

   6    12     9  

Uncollectible accounts expense — provision(b)

   (2  3     (1

Uncollectible accounts expense — recovery, net(b)

   (4  34     (12

BSC allocations(c)

   18  

Other(c)

   13    29     (2
  

 

  

 

   

 

 
   24    124     8  

Regulatory required programs

     

Energy efficiency and demand response programs

   21    2     (18
  

 

  

 

   

 

 
   21    2     (18
  

 

  

 

   

 

 

Increase in operating and maintenance expense

  $45   $126  

Total increase (decrease)

  $(10
  

 

  

 

   

 

 

 

(a)

Primarily reflects increased contracting costs related to preventative maintenancethe favorable impact of higher assumed pension and other projects for the three and nine months ended September 30, 2015.OPEB discount rates in 2016.

(b)

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2015,March 31, 2016, ComEd recorded a net reduction and increase, respectively,decrease in operatingOperating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting amountdecrease has been recognized in operating revenue for the periods presented.

(c)

Primarily reflects increased ITinformation technology support services costs from BSC.BSC during 2016.

Depreciation and Amortization Expense

The increase in Depreciation and amortization expense forduring the three months ended September 30, 2015,March 31, 2016, compared to the same period in 2014, remained relatively consistent.2015, consisted of the following:

Depreciation and amortization expense increased for the nine months ended September 30, 2015, compared to the same period in 2014 primarily due to increased capital expenditures, partially offset by decreased amortization as a result of ComEd’s severance regulatory assets fully amortizing during the second quarter of 2014.

   Increase (Decrease) 

Depreciation expense(a)

  $13  

Amortization regulatory assets

   (2

Other

   3  
  

 

 

 

Total increase (decrease)

  $14  
  

 

 

 

(a)

Depreciation expense increased due to ongoing capital expenditures.

Taxes Other Than Income

Taxes other than income, taxes, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively flatwere consistent during the three and nine months ended September 30, 2015,March 31, 2016, compared to the same periodsperiod in 2014.2015.

Gain on Sales of Assets

The increase in Gain on sales of assets during the three months ended March 31, 2016, compared to the same period in 2015, is primarily due to the sale of land during March 2016.

Interest Expense, Net

The changes in interestInterest expense, net forremained relatively consistent during the three and nine months ended September 30, 2015,March 31, 2016, compared to the same periodsperiod in 2014, consisted of the following:2015.

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   Increase
(Decrease)
  Increase
(Decrease)
 

Interest expense related to uncertain tax positions

  $1   $  

Interest expense on debt (including financing trusts)(a)

   3    9  

Other

   (2  (2
  

 

 

  

 

 

 

Increase in interest expense, net

  $2   $7  
  

 

 

  

 

 

 

(a)

Primarily reflects an increase in interest expense due to the issuance of First Mortgage Bonds on November 10, 2014 and March 2, 2015. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s debt obligations.

Effective Income Tax Rate

ComEd’s effective income tax rate was 39.9%40.1% and 40.0%39.6% for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively. ComEd’s effective income tax rate was 40.0% and 39.7% for the nine months ended September 30, 2015 and 2014, respectively. See Note 1211 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ComEd Electric Operating Statistics and Revenue Detail

 

 Three Months Ended
September 30,
 % Change  Weather-
Normal
% Change
  Nine Months Ended
September 30,
 % Change  Weather-
Normal
% Change
   Three Months Ended
March 31,
   % Change  Weather-Normal
% Change
 

Retail Deliveries to Customers (in GWhs)

 2015 2014 2015 2014       2016           2015        

Retail Deliveries(a)

             

Residential

  7,919    7,332    8.0%    (0.6)%    20,602    20,920    (1.5)%   (1.8)%    6,376     6,997     (8.9)%   (2.6)% 

Small commercial & industrial

  8,579    8,366    2.5%    0.3%    24,305    24,456    (0.6)%   (0.4)%    7,879     8,161     (3.5)%   (0.2)% 

Large commercial & industrial

  7,250    7,245    0.1%    (1.3)%    20,807    21,109    (1.4)%   (1.3)%    6,756     6,877     (1.8)%   1.3

Public authorities & electric railroads

  295    301    (2.0)%    (2.1)%    964    1,001    (3.7)%   (3.1)%    361     379     (4.7)%   (0.8)% 
 

 

  

 

    

 

  

 

     

 

   

 

    

Total retail deliveries

  24,043    23,244    3.4%    (0.5)%    66,678    67,486    (1.2)%   (1.2)%    21,372     22,414     (4.6)%   (0.5)% 
 

 

  

 

    

 

  

 

     

 

   

 

    
 As of September 30,               As of March 31,       

Number of Electric Customers

 2015 2014               2016   2015       

Residential

  3,524,253    3,486,438           3,566,896     3,511,271     

Small commercial & industrial

  369,151    367,446           372,254     369,424     

Large commercial & industrial

  1,996    1,992           1,955     1,966     

Public authorities & electric railroads

  4,826    4,821           4,821     4,843     
 

 

  

 

         

 

   

 

    

Total

  3,900,226    3,860,697           3,945,926     3,887,504     
 

 

  

 

         

 

   

 

    
 Three Months Ended
September 30,
     Nine Months Ended
September 30,
       Three Months Ended
March 31,
       

Electric Revenue

 2015 2014 % Change   2015 2014 % Change     2016   2015   % Change   

Retail Sales(a)

               

Residential

 $690   $566    21.9%    $1,785   $1,572    13.5%     $609    $568     7.2 

Small commercial & industrial

  361    349    3.4%     1,029    1,033    (0.4)%      321     338     (5.0)%  

Large commercial & industrial

  121    115    5.2%     339    343    (1.2)%      107     109     (1.8)%  

Public authorities & electric railroads

  10    10    —%     33    35    (5.7)%      12     12      
 

 

  

 

    

 

  

 

     

 

   

 

    

Total retail

  1,182    1,040    13.7%     3,186    2,983    6.8%      1,049     1,027     2.1 
 

 

  

 

    

 

  

 

     

 

   

 

    

Other revenue(b)

  194    182    6.6%     523    501    4.4%      200     158     26.6 
 

 

  

 

    

 

  

 

     

 

   

 

    

Total electric revenue

 $1,376   $1,222    12.6%    $3,709   $3,484    6.5%     $1,249    $1,185     5.4 
 

 

  

 

    

 

  

 

     

 

   

 

    

 

(a)

Reflects delivery revenue and volumesvolume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.

(b)

Other revenue primarily includes transmission revenue from PJM. Other items includerevenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of environmentalremediation costs associated with MGP sites.

Results of Operations — PECO

 

 Three Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
   Three Months Ended
March 31,
 Favorable
(Unfavorable)
Variance
 
     2015         2014         2015         2014           2016         2015     

Operating revenue

 $740   $693   $47   $2,386   $2,343   $43  

Operating revenues

  $841   $985   $(144

Purchased power and fuel

  278    255    (23  953    960    7     321    438    117  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Revenue net of purchased power and fuel expense(a)

  462    438    24    1,433    1,383    50  

Revenue net of purchased power and fuel(a)

   520    547    (27
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other operating expenses

          

Operating and maintenance

  196    204    8    609    668    59     215    222    7  

Depreciation and amortization

  68    59    (9  198    176    (22   67    62    (5

Taxes other than income

  44    42    (2  125    122    (3   42    41    (1
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other operating expenses

  308    305    (3  932    966    34     324    325    1  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Gain on sale of assets

              1        1  

Gain on sales of assets

       1    (1
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Operating income

  154    133    21    502    417    85     196    223    (27
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other income and (deductions)

          

Interest expense, net

  (28  (29  1    (84  (85  1     (31  (28  (3

Other, net

  1    2    (1  3    5    (2   2    2      
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other income and (deductions)

  (27  (27      (81  (80  (1   (29  (26  (3
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Income before income taxes

  127    106    21    421    337    84     167    197    (30

Income taxes

  37    25    (12  122    82    (40   43    58    15  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Net income attributable to common shareholder

 $90   $81   $9   $299   $255   $44    $124   $139   $(15
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

 

(a)

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentationpresentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

Net Income Attributableattributable to Common Shareholdercommon shareholder

Three Months Ended September 30, 2015March 31, 2016 Compared to Three Months Ended September 30, 2014.March 31, 2015.    PECO’s net income attributable to common shareholder for the three months ended September 30, 2015 was higher thandecreased from the same period in 2014,2015, primarily due to favorable weather.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014.    PECO’s net income attributable to common shareholder for the nine months ended September 30, 2015 was higher than the same period in 2014, primarily due to favorable weather and a decrease in operating and maintenance expense due to a decrease in storm costs.revenue net of purchased power and fuel expense as a result of unfavorable weather partially offset by increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective January 1, 2016.

Operating RevenueRevenues Net of Purchased Power and Fuel Expense

Electric and gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO’s electric supply and natural gas cost rates charged to customers are subject to

adjustments as specified in the PAPUC-approved tariffsat least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with

PECO’s the PAPUC’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and gas revenue net of purchased power and fuel expense.

Electric and gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customer’scustomers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and gas revenue net of purchased power and fuel expense.

Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30,March 31, 2016 and 2015, and 2014, consisted of the following:

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
  2015 2014 2015 2014   2016 2015 

Electric

   69  70  69  70   69  67

Natural Gas

   31  27  24  22   25  23

Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30,March 31, 2016 and 2015 and 2014 consisted of the following:

 

  September 30, 2015 September 30, 2014   March 31, 2016 March 31, 2015 
  Number of
customers
   % of  total
retail
customers
 Number of
customers
   % of  total
retail
customers
   Number of
customers
   % of total
retail
customers
 Number of
customers
   % of total
retail
customers
 

Electric

   558,300     35  537,000     34   570,000     35  551,000     34

Natural Gas

   81,100     16  76,200     15   80,600     16  80,200     16

The changes in PECO’s operating revenuerevenues net of purchased power and fuel expense for the three and nine months ended September 30, 2015March 31, 2016 compared to the same period in 20142015 consisted of the following:

 

  Three Months Ended
September 30,
 Nine Months Ended
September 30,
 
  Increase (Decrease) Increase (Decrease)   Increase (Decrease) 
  Electric Gas   Total Electric Gas   Total   Electric Gas Total 

Weather

  $32   $    $32   $52   $1    $53    $(40 $(32 $(72

Volume

   (1       (1  3    5     8     4    5    9  

Pricing

   (7       (7  (8  2     (6   56    (1  55  

Regulatory required programs

   1         1    4         4     (18      (18

Other

   (1       (1  (10  1     (9   (2  1    (1
  

 

  

 

   

 

  

 

  

 

   

 

   

 

  

 

  

 

 

Total increase

  $24   $    $24   $41   $9    $50  

Total increase (decrease)

  $   $(27 $(27
  

 

  

 

   

 

  

 

  

 

   

 

   

 

  

 

  

 

 

Weather.    The demand for electricity and gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 2014,2015, operating revenue net of purchased power and fuel expense was higher primarilylower due to the impact of favorableunfavorable winter weather conditions in PECO’s service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodperiods in 20142015 and normal weather consisted of the following:

 

      % Change   Three Months Ended
March 31,
   Normal   % Change 

Heating and Cooling Degree-Days

  2015   2014   Normal   From 2014 From Normal       2016           2015       2016 vs. 2015 2016 vs. Normal 

Three Months Ended September 30,

                  

Heating Degree-Days

        14     38     (100.0)%   (100.0)%    2,137     2,934     2,477     (27.2)%   (13.7)% 

Cooling Degree-Days

   1,186     911     929     30.2  27.7   5          1     n/a    400.0

Nine Months Ended September 30,

                  

Heating Degree-Days

   3,264     3,251     2,981     0.4  9.5

Cooling Degree-Days

   1,699     1,286     1,278     32.1  32.9

Volume.    The increase in gas operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the ninethree months ended September 30, 2015March 31, 2016 compared to the same period in 2014,2015, primarily reflects the impact of moderate economic and customer growth partially offset by energy efficiency initiatives on customer usages.

The increase inusages for electric operating revenue net of purchased power expense related to delivery volume for the nine months ended September 30, 2015, is primarily related to theand gas and a shift in the volume profile across classes from lower priced classes to higher priced classes.classes for electric.

Pricing.    The decreaseincrease in electric operating revenues net of purchased power and fuel expense as a result of pricing for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 2014 is2015 primarily attributablereflects an increase in electric distribution rates charged to lower overallcustomers. The increase in electric distribution rates was effective rates dueJanuary 1, 2016 in accordance with the 2015 PAPUC approved electric distribution rate case settlement. See Note 3 —Regulatory Matters of the Combined Notes to increased usage across all major customer classes.the Consolidated Financial Statements in the 2015 Form 10-K for further information.

Regulatory Required Programs.    This represents the change in operating revenue collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes. The decrease in revenue from regulatory required programs for the three months ended March 31, 2016 compared to the same period in 2015 is primarily the result of smart meter costs reflected in base rates in accordance with the 2015 PAPUC approved electric distribution rate case settlement effective January 1, 2016. Refer to the Operating and maintenance expense discussion below for additional information on included programs.

Other.    Other revenue, for electricwhich can vary period to period, primarily reflects the impact of lowerincludes wholesale transmission revenue, for the threerental revenue, revenue related to late payment charges and nine months ended September 30, 2015 comparedassistance provided to the same periods in 2014. Wholesale transmission revenue is impacted by the previous year’s peak demand, which was lower in 2014 than in 2013.other utilities through mutual assistance programs.

Operating and Maintenance Expense

 

 Three Months Ended
September 30,
 Increase
(Decrease)
  Nine Months Ended
September 30,
 Increase
(Decrease)
  Three Months Ended
March 31,
 Increase
(Decrease)
 
 2015 2014 2015 2014      2016         2015     

Operating and maintenance expense — baseline

 $170   $178   $(8 $528   $592   $(64 $195   $196   $(1

Operating and maintenance expense — regulatory required programs(a)

  26    26        81    76    5    20    26    (6
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

Total operating and maintenance expense

 $196   $204   $(8 $609   $668   $(59 $215   $222   $(7
 

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

  

 

 

 

(a)

Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenue.

The changes in operating and maintenance expense for the three and nine months ended September 30, 2015March 31, 2016 compared to the same period in 2014,2015, consisted of the following:

 

  Three Months Ended
September 30, 2015
 Nine Months Ended
September 30, 2015
 
  Increase
(Decrease)
 Increase
(Decrease)
   Increase
(Decrease)
 

Baseline

     

Labor, other benefits, contracting and materials

  $(2 $(1  $(2

Storm-related costs

   (18)(a)   (78)(b)    3  

Pension and non-pension postretirement benefits expense

   1    2     (1

Merger and integration costs

   1    4  

PHI merger and integration costs

   3  

BSC allocation(a)

   11  

Uncollectible accounts expense

   2    (3   (17

Other

   8    12     2  
  

 

  

 

   

 

 
   (8  (64   (1

Regulatory required programs

   

Smart meter

   (2  (3

Energy efficiency

   2    8  

Regulatory Required Programs

  

Smart Meter

   (7

Energy Efficiency

   2  

Other

            (1
  

 

  

 

   

 

 
       5     (6
  

 

  

 

   

 

 

Increase (Decrease) in operating and maintenance expense

  $(8 $(59

Total increase (decrease)

  $(7
  

 

  

 

   

 

 

 

(a)

Reflects a reduction of $17 million in incremental storm costs in the third quarter of 2015 as a result of the significant 2014 storms.

(b)

Reflects a reduction of $68 million in incremental storm costsPrimarily reflects increased information technology support services from BSC during 2015 primarily as a result of the February 5, 2014 ice storm.2016.

Depreciation and Amortization Expense

The increasechanges in depreciation and amortization expense for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 2014 primarily reflects2015, consisted of the following:

   Increase (Decrease)
2016 vs. 2015
 

Depreciation and amortization expense(a)

  $2  

Regulatory asset amortization(b)

   3  
  

 

 

 

Total increase (decrease)

  $5  
  

 

 

 

(a)

Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization increased for the three months ended March 31, 2016 compared to the same periods in 2015 due to an increase in regulatory asset amortization related to AMI programs and CAP Arrearage.

Taxes Other Than Income

Taxes other than income for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 20142015 remained relatively consistent.

Interest Expense, Net

The increase in Interest expense, net for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 2014 remained relatively consistent.2015 primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in October 2015.

Other, Net

Other, net for the three and nine months ended September 30, 2015March 31, 2016 remained relatively consistent compared to the same periodsperiod in 2014 remained relatively consistent.2015.

Effective Income Tax Rate

PECO’s effective income tax rate was 29.1%25.7% and 23.6%29.4% for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively. PECO’s effective income tax rate was 29.0% and 24.3% for the nine months ended September 30, 2015 and 2014, respectively. See Note 12—11 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.

PECO Electric Operating Statistics and Revenue Detail

 

 Three Months Ended
September 30,
 %
Change
  Weather  -
Normal
% Change
  Nine Months
Ended
September 30,
 %
Change
  Weather -
Normal
% Change
   Three Months Ended
March 31,
   % Change  Weather -
Normal
% Change
 

Retail Deliveries to Customers (in GWhs)

 2015 2014 2015 2014   2016   2015    

Retail Deliveries(a)

             

Residential

  3,940    3,551    11.0%    (2.3)%    10,929    10,200    7.1  (0.4)%    3,415     3,968     (13.9)%   1.3

Small commercial & industrial

  2,219    2,096    5.9%    1.0%    6,306    6,098    3.4  0.6   2,025     2,162     (6.3)%   4.8

Large commercial & industrial

  4,227    4,086    3.5%    0.7%    11,744    11,604    1.2  (0.1)%    3,594     3,734     (3.7)%   (3.1)% 

Public authorities & electric railroads

  224    241    (7.1)%    (7.1)%    667    722    (7.6)%   (7.6)%    227     228     (0.4)%   (0.4)% 
 

 

  

 

    

 

  

 

     

 

   

 

    

Total retail deliveries

  10,610    9,974    6.4%    (0.5)%    29,646    28,624    3.6  (0.2)%    9,261     10,092     (8.2)%   0.3
 

 

  

 

    

 

  

 

     

 

   

 

    
 As of September 30,               As of March 31,       

Number of Electric Customers

 2015 2014               2016   2015       

Residential

  1,439,951    1,429,293           1,449,470     1,439,005     

Small commercial & industrial

  148,920    149,172           149,388     149,192     

Large commercial & industrial

  3,093    3,103           3,092     3,102     

Public authorities & electric railroads

  9,801    9,737           9,807     9,771     
 

 

  

 

         

 

   

 

    

Total

  1,601,765    1,591,305           1,611,757     1,601,070     
 

 

  

 

         

 

   

 

    
 Three Months Ended
September 30,
 %
Change
    Nine Months  Ended
September 30,
 %
Change
      Three Months Ended
March 31,
   % Change    

Electric Revenue

 2015 2014   2015 2014     2016   2015    

Retail Sales(a)

               

Residential

 $461   $413    11.6%    $1,276   $1,195    6.8%     $410    $450     (8.9)%  

Small commercial & industrial

  113    107    5.6%     330    319    3.4%      119     115     3.5 

Large commercial & industrial

  58    52    11.5%     166    169    (1.8)%      58     53     9.4 

Public authorities & electric railroads

  8    7    14.3%     23    23    —%      8     8      
 

 

  

 

    

 

  

 

     

 

   

 

    

Total retail

  640    579    10.5%     1,795    1,706    5.2%      595     626     (5.0)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

Other revenue(b)

  51    55    (7.3)%     155    165    (6.1)%      49     51     (3.9)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

Total electric revenue

 $691   $634    9.0%    $1,950   $1,871    4.2%     $644    $677     (4.9)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

 

(a)

Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b)

Other revenue includes transmission revenue from PJM and wholesale electric revenue.

PECO Gas Operating Statistics and Revenue Detail

 

 Three Months Ended
September 30,
 % Change  Weather  -
Normal
% Change
  Nine Months Ended
September 30,
 % Change  Weather  -
Normal
% Change
   Three Months Ended
March 31,
   % Change  Weather  -
Normal
% Change
 

Deliveries to Customers (in mmcf)

 2015 2014 2015 2014   2016   2015    

Retail Delivery

              

Retail sales(a)

  3,639    3,893    (6.5)%   (3.2)%   45,734    44,487    2.8  3.2   27,111     34,863     (22.2)%   4.6

Transportation and other

  7,457    5,750    29.7  17.5  21,585    20,124    7.3  2.9   7,696     8,696     (11.5)%   1.4
 

 

  

 

    

 

  

 

     

 

   

 

    

Total gas deliveries

  11,096    9,643    15.1  9.3  67,319    64,611    4.2  3.1   34,807     43,559     (20.1)%   4.0
 

 

  

 

    

 

  

 

     

 

   

 

    
 As of September 30,               As of March 31,       

Number of Gas Customers

 2015 2014               2016   2015       

Residential

  465,023    459,678           468,808     464,344     

Commercial & industrial

  42,544    42,008           43,313     42,941     
 

 

  

 

         

 

   

 

    

Total retail

  507,567    501,686           512,121     507,285     

Transportation

  837    866           817     847     
 

 

  

 

         

 

   

 

    

Total

  508,404    502,552           512,938     508,132     
 

 

  

 

         

 

   

 

    
 Three Months Ended
September 30,
 % Change    Nine Months Ended
September 30,
 % Change      Three Months Ended
March 31,
   % Change    

Gas Revenue

 2015 2014   2015 2014     2016   2015    

Retail Sales

               

Retail sales(a)

 $42   $54    (22.2)%   $410   $444    (7.7)%    $187    $296     (36.8)%  

Transportation and other

  7    5    40.0   26    28    (7.1)%     10     12     (16.7)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

Total gas revenue

 $49   $59    (16.9)%   $436   $472    (7.6)%  

Total gas revenues

  $197    $308     (36.0)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

 

(a)

Reflects delivery volumes and revenue from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

Results of Operations — BGE

 

 Three Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
  Nine Months Ended
September 30,
 Favorable
(Unfavorable)
Variance
   Three Months Ended
March 31,
 Favorable
(Unfavorable)
Variance
 
 2015 2014 2015 2014       2016         2015     

Operating revenue

 $725   $697   $28   $2,388   $2,404   $(16

Operating revenues

  $929   $1,036   $(107

Purchased power and fuel

  311    297    (14  1,037    1,094    57     373    487    114  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Revenue net of purchased power and fuel(a)

  414    400    14    1,351    1,310    41     556    549    7  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other operating expenses

          

Operating and maintenance

  169    165    (4  499    541    42     202    182    (20

Depreciation and amortization

  79    78    (1  271    275    4     109    106    (3

Taxes other than income

  57    55    (2  169    168    (1   58    57    (1
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other operating expenses

  305    298    (7  939    984    45     369    345    (24
 

 

  

 

  

 

  

 

  

 

  

 

 

Gain on sale

  1        1    1        1  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Operating income

  110    102    8    413    326    87     187    204    (17
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Other income and (deductions)

          

Interest expense, net

  (25  (26  1    (73  (81  8     (24  (25  1  

Other, net

  4    4        13    14    (1   4    4      
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Total other income and (deductions)

  (21  (22  1    (60  (67  7     (20  (21  1  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Income before income taxes

  89    80    9    353    259    94     167    183    (16

Income taxes

  35    31    (4  141    103    (38   66    74    8  
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Net income

  54    49    5    212    156    56     101    109    (8

Preference stock dividends

  3    3        10    10         3    3      
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

Net income attributable to common shareholder

 $51   $46   $5   $202   $146   $56    $98   $106   $(8
 

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

  

 

 

 

(a)

BGE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of purchased fuel expense for gas sales. BGE believes revenue net of purchased power and revenue net of purchased fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

Net Income attributableAttributable to common shareholderCommon Shareholder

Three Months Ended September 30, 2015,March 31, 2016 Compared to Three Months Ended September 30, 2014March 31, 2015.    BGE’s net income attributable to common shareholder for the three months ended September 30, 2015March 31, 2016 was higherlower than the same period in 2014,2015, primarily due to an increase in revenue net of purchased poweroperating and fuelmaintenance expense as a result of the December 2014 electric and gas distribution rate order issued by the MDPSC and lowerincreased storm costs in the BGEBGE’s service territory, which is included in operating and maintenance expense.territory.

Nine Months Ended September 30, 2015, Compared to Nine Months Ended September 30, 2014.    BGE’s net income attributable to common shareholder for the nine months ended September 30, 2015 was higher than the same period in 2014, primarily due to an increase in revenue net of purchased power and fuel expense as a result of the December 2014 electric and gas distribution rate order issued by the MDPSC and a reduction in bad debt expense and lower storm costs in the BGE service territory, which are included in operating and maintenance expense.

Operating RevenueRevenues Net of Purchased Power and Fuel Expense

There are certain drivers to operatingOperating revenue that are offset by their impact on purchasedPurchased power expense and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric generation or natural gas supplier. Electric and gasOperating revenue and purchasedPurchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.

The

Electric and gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to select a competitive electric generation supplier affects electric SOS revenue and purchased power expense. The number of customers electing to select a competitiveor natural gas supplier affects gas cost adjustment revenue and purchased natural gas expense.supplier. All BGE customers have the choice to purchase energyelectricity and gas from a competitive electric generation supplier. This customerand natural gas suppliers, respectively. The customers’ choice of electric generation suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to SOS.supplied energy and natural gas service.

Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2015,March 31, 2016, compared to the same period in 2014,2015, consisted of the following:

 

  Three Months Ended September 30, Nine Months Ended September 30,   Three Months Ended
March 31,
 
  2015 2014 2015 2014     2016     2015   

Electric

   60  60  59  60   57  56

Natural Gas

   76  73  54  55   49  45

Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30,March 31, 2016 and 2015 and 2014 consisted of the following:

 

  September 30, 2015 September 30, 2014   March 31, 2016 March 31, 2015 
  Number of
customers
   % of total
retail
customers
 Number
of
customers
   % of total
retail
customers
   Number of
Customers
   % of total
retail
customers
 Number of
customers
   % of total
retail
customers
 

Electric

   346,400     28  369,300     30   341,800     27  355,000     28

Natural Gas

   154,900     24  161,500     25   153,500     23  158,000     24

The changes in BGE’s operating revenuerevenues net of purchased power and fuel expense for the three and nine months ended September 30, 2015,March 31, 2016, compared to the same period in 2014,2015, consisted of the following:

 

  Three Months Ended September 30,   Nine Months Ended September 30,   Increase (Decrease) 
  Increase (Decrease)   Increase (Decrease)   Electric Gas Total 
  Electric Gas   Total   Electric   Gas Total 

Distribution rate increase

  $2   $4    $6    $12    $25   $37  

Regulatory required programs

   7         7     8     2    10    $(1 $(1 $(2

Transmission revenue

   12        12  

Other

   (1  2     1     (4)     (2  (6   3    (6  (3
  

 

  

 

   

 

   

 

   

 

  

 

   

 

  

 

  

 

 

Total increase

  $8   $6    $14    $16    $25   $41  

Total increase (decrease)

  $14   $(7 $7  
  

 

  

 

   

 

   

 

   

 

  

 

   

 

  

 

  

 

 

Revenue Decoupling.    The demand for electricity and gas is affected by weather and usage conditions. The MDPSC has allowedallows BGE to record a monthly adjustment to its electric and gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE’s electric and gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue

per customer, by customer class, regardless of changes in consumption levels. This meansallows BGE recognizesto recognize revenue at MDPSC-approved levels per customer, regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while these revenues arethis revenue is affected by customer growth, theyit will not be affected by actual weather or usage conditions. BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes in heating degree days in BGE’s service territory for the three and nine months ended September 30, 2015March 31, 2016 compared to the same period in 20142015 consisted of the following:

 

Heating and Cooling Degree-Days

  2015   2014   Normal   % Change 

Three Months Ended September 30,

              From 2014  From Normal 

Heating Degree-Days

   46     82     81     (43.9)%   (43.2)% 

Cooling Degree-Days

   592     484     593     22.3  (0.2)% 

Nine Months Ended September 30,

                   

Heating Degree-Days

   3,418     3,439     2,985     (0.6)%   14.5

Cooling Degree-Days

   909     717     849     26.8  7.1

Distribution Rate Increase.    The increase in distribution rates for the three and nine months ended September 30, 2015, compared to the same period in 2014, was primarily due to the impact of the new electric and natural gas distribution rates charged to customers that became effective in December 2014 in accordance with the MDPSC approved electric and natural gas distribution rate case orders. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information.

   Three Months Ended
March 31,
       % Change 

Heating and Cooling Degree-Days

      2016           2015       Normal   2016 vs. 2015  2016 vs. Normal 

Heating Degree-Days

   2,280     2,950     2,412     (22.7)%   (5.5)% 

Cooling Degree-Days

                  n/a    n/a  

Regulatory Required Programs.    This represents the change in revenue collected under approved riders to recover costs incurred for the energy efficiency and demand response programs as well as administrative and commercial and industrial customer bad debt costs for SOS. The riders are designed to provide full recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in BGE’s Consolidated Statements of Operations and Comprehensive Income.

Transmission Revenue.    Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and other billing determinants. During the three months ended March 31, 2016 compared to the same period in 2015, the increase in transmission revenue was primarily due to an increase in capital investment and operating and maintenance expense. See Operating and Maintenance Expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other.Other revenue, which can vary from period to period, includes miscellaneous revenue such as service application and late payment fees.

Operating and Maintenance Expense

The changes in operating and maintenance expense for the three and nine months ended September 30, 2015March 31, 2016 compared to the same period in 2014,2015, consisted of the following:

 

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   Increase
(Decrease)
  Increase
(Decrease)
 

Labor, other benefits, contracting and materials

  $4   $  

Storm-related costs

   (5  (23

Uncollectible accounts expense

   (3  (23

Other

   8    4  
  

 

 

  

 

 

 

Increase (Decrease) in operating and maintenance expense

  $4   $(42
  

 

 

  

 

 

 
   Increase (Decrease) 

Labor, other benefits, contracting and materials

  $2  

Storm-related costs

   17  

Uncollectible accounts expense(a)

   (13

City of Baltimore conduit lease(b)

   7  

BSC allocations(c)

   7  
  

 

 

 

Total increase (decrease)

  $20  
  

 

 

 

(a)

Uncollectible accounts decreased primarily due to milder weather and improved customer behavior for the three months ended March 31, 2016 compared to the same period in 2015.

(b)

City of Baltimore conduit fees increased for the three months ended March 31, 2016 compared to the same period in 2015 as a result of increased rental fees assessed by the City of Baltimore. See Executive Overview—Environmental Legislative and Regulatory Developments above and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(c)

Primarily reflects increased information technology support services from BSC during 2016.

Conduit Lease with City of Baltimore

On September 23, 2015, the Baltimore City Board of Estimates approved an increase in rental fees for access to the Baltimore City conduit system to be effective November 1, 2015, which will result in an increase to operating and maintenance expense of $30 million in 2016 subject to an annual increase based on the Consumer Price Index. BGE will seek recovery of this incremental expense in its next base rate case proceeding. On October 16, 2015, BGE filed a lawsuit against the City in the Circuit Court for Baltimore City to protect its customers from any improper use by the City of the conduit fee revenues and to place constraints on the City’s ability to set the conduit fee in the future.

Depreciation and Amortization

DepreciationThe changes in depreciation and amortization expense for the three months ended September 30, 2015March 31, 2016 compared to the same period in 2014 remained relatively consistent.2015 consisted of the following:

Depreciation and amortization expense decreased for the nine months ended September 30, 2015 compared to the same period in 2014 primarily due to a reduction in regulatory asset amortization related to demand response programs and revised recovery periods for certain regulatory assets that became effective in January 2015 in accordance with the MDPSC approved 2014 electric and natural gas distribution rate case orders.

   Increase (Decrease) 

Depreciation expense(a)

  $4  

Regulatory asset amortization(b)

   (1
  

 

 

 

Total increase (decrease)

  $3  
  

 

 

 

(a)

Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization decreased for the three months ended March 31, 2016 compared to the same periods in 2015 due to a reduction in regulatory asset amortization related to demand response programs.

Taxes Other Than Income

Taxes other than income, taxes, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2015March 31, 2016 compared to the same periodsperiod in 20142015 remained relatively consistent.

Interest Expense, Net

The decrease in interestInterest expense, net forremained relatively consistent during the three and nine months ended September 30, 2015,March 31, 2016, compared to the same periodsperiod in 2014, consisted of the following:2015 .

   Three Months Ended
September 30,
  Nine Months Ended
September 30,
 
   Increase
(Decrease)
  Increase
(Decrease)
 

Interest expense on debt (including financing trusts)

  $(1 $(3

Interest expense related to capitalization of interest / AFUDC

   (1  (2

Interest expense related to uncertain tax positions

       (1

Other

   1    (2
   

 

 

 

Increase (Decrease) in interest expense, net

  $(1 $(8
  

 

 

  

 

 

 

Effective Income Tax Rate

BGE’s effective income tax rate was 39.3%39.5% and 38.8%40.4% for the three months ended September 30,March 31, 2016 and 2015, and 2014, respectively, and 39.9% and 39.8% for the nine months ended September 30, 2015 and 2014, respectively. See Note 1211 — Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussionadditional information regarding the components of the change in effective income tax rate.rates.

BGE Electric Operating Statistics and Revenue Detail

 

 Three Months Ended
September 30,
 % Change  Weather  -
Normal
% Change
  Nine Months Ended
September 30,
 % Change  Weather -
Normal
% Change
   Three Months Ended
March 31,
   % Change  Weather -
Normal
% Change
 

Retail Deliveries to Customers (in
GWhs)

 2015 2014 2015 2014   2016   2015    

Retail Deliveries(a)

              

Residential

  3,458    3,291    5.1  n.m.    10,266    10,023    2.4  n.m.     3,479     4,173     (16.6)%   n.m.  

Small commercial & industrial

  788    805    (2.1)%   n.m.    2,413    2,343    3.0  n.m.     774     845     (8.4)%   n.m.  

Large commercial & industrial

  3,829    3,818    0.3  n.m.    10,735    10,880    (1.3)%   n.m.     3,219     3,439     (6.4)%   n.m.  

Public authorities & electric railroads

  75    79    (5.1)%   n.m.    224    236    (5.1)%   n.m.     71     75     (5.3)%   n.m.  
 

 

  

 

    

 

  

 

   
  

 

   

 

    

Total electric deliveries

  8,150    7,993    2.0  n.m.    23,638    23,482    0.7  n.m.     7,543     8,532     (11.6)%   n.m.  
 

 

  

 

    

 

  

 

     

 

   

 

    
 As of September 30,               As of March 31,       

Number of Electric Customers

 2015 2014               2016   2015       

Residential

  1,132,836    1,123,644           1,141,814     1,131,621     

Small commercial & industrial

  112,888    112,580           113,034     112,811     

Large commercial & industrial

  11,863    11,707           11,932     11,777     

Public authorities & electric railroads

  286    290           282     286     
 

 

  

 

         

 

   

 

    

Total

  1,257,873    1,248,221           1,267,062     1,256,495     
 

 

  

 

         

 

   

 

    
 Three Months Ended
September 30,
 % Change    Nine Months Ended
September 30,
 % Change      Three Months Ended
March 31,
   % Change    

Electric Revenue

 2015 2014   2015 2014     2016   2015    

Retail Sales(a)

               

Residential

 $379   $348    8.9  $1,131   $1,077    5.0   $428    $449     (4.7)%  

Small commercial & industrial

  70    72    (2.8)%    208    208        73     76     (3.9)%  

Large commercial & industrial

  122    134    (9.0)%    351    377    (6.9)%     100     120     (16.7)%  

Public authorities & electric railroads

  9    8    12.5   24    24        9     8     12.5 
 

 

  

 

    

 

  

 

     

 

   

 

    

Total retail

  580    562    3.2   1,714    1,686    1.7    610     653     (6.6)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

Other revenue

  75    69    8.7   194    207    (6.3)%     70     60     16.7 
 

 

  

 

    

 

  

 

     

 

   

 

    

Total electric revenue

 $655   $631    3.8  $1,908   $1,893    0.8   $680    $713     (4.6)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

 

(a)

Reflects delivery volumes and revenue from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.

BGE Gas Operating Statistics and Revenue Detail

 

 Three Months Ended
September 30,
 % Change  Weather  -
Normal
% Change
  Nine Months Ended
September 30,
 % Change  Weather -
Normal
%
Change
   Three Months Ended
March 31,
   % Change  Weather -
Normal
% Change
 

Deliveries to Customers (in mmcf)

 2015 2014 2015 2014   2016   2015    

Retail Deliveries(b)(a)

               

Retail sales

  11,719    10,257    14.3  n.m.    72,481    71,479    1.4  n.m.     38,584     46,877     (17.7)%   n.m.  

Transportation and other

  612    304    101.3  n.m.    4,521    7,508    (39.8)%   n.m.  

Transportation and other(b)

   2,496     3,325     (24.9)%   n.m.  
 

 

  

 

    

 

  

 

     

 

   

 

    

Total gas deliveries

  12,331    10,561    16.8  n.m.    77,002    78,987    (2.5)%   n.m.     41,080     50,202     (18.2)%   n.m.  
 

 

  

 

    

 

  

 

     

 

   

 

    
 As of September 30,       As of March 31,       

Number of Gas Customers

 2015 2014               2016   2015       

Residential

  613,571    610,750           619,130     612,814     

Commercial & industrial

  43,885    43,963           44,224     44,199     
 

 

  

 

         

 

   

 

    

Total

  657,456    654,713           663,354     657,013     
 

 

  

 

         

 

   

 

    
 Three Months Ended
September 30,
 % Change     Nine Months Ended
September 30,
 % Change      Three Months Ended
March 31,
   % Change    

Gas Revenue

 2015 2014 2015 2014   2016   2015    

Retail Sales(b)(a)

           

Retail sales

 $66   $62    6.5  $450   $439    2.5   $238    $299     (20.4)%  

Transportation and other(c)

  4    4       30    72    (58.3)%  

Transportation and other(b)

   11     24     (54.2)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

Total gas revenue

 $70   $66    6.1  $480   $511    (6.1)%  

Total gas revenues

  $249    $323     (22.9)%  
 

 

  

 

    

 

  

 

     

 

   

 

    

 

(b)(a)

Reflects delivery volumes and revenue from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from BGE.

(c)(b)

Transportation and other gas revenue includes off-system revenue of 6122,496 mmcfs ($39 million) and 3043,325 mmcfs ($223 million) for the three months ended September 30,March 31, 2016 and 2015, respectively.

Results of Operations — PHI

PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE for all periods presented below. For “Predecessor” reporting periods, PHI’s results of operations also include the results of PES and PCI. See Note 20—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding PHI’s reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for Pepco, DPL and ACE is presented elsewhere in this report.

As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The “Predecessor” reporting periods represent PHI’s results of operations for the three months ended March 31, 2015 and the period of January 1, 2016 to March 23, 2016. The “Successor “ reporting period represents PHI’s results of operations for the period of March 24, 2016 to March 31, 2016. All amounts presented below are before the impact of income taxes, except as noted.

   Successor  Predecessor 
   March 24,
2016 to
March 31,
2016
  January 1,
2016 to
March 23,
2016
  Three
Months
Ended
March 31,
2015
  Favorable
(Unfavorable)
Variance
 

Operating revenues

  $105   $1,153   $1,354   $(201

Purchased power and fuel

   38    497    639    142  
  

 

 

  

 

 

  

 

 

  

 

 

 

Revenue net of purchased power and fuel(a)

   67    656    715    (59
  

 

 

  

 

 

  

 

 

  

 

 

 

Other operating expenses

      

Operating and maintenance

   449    294    300    6  

Depreciation and amortization

   14    152    155    3  

Taxes other than income

   15    105    118    13  
  

 

 

  

 

 

  

 

 

  

 

 

 

Total other operating expenses

   478    551    573    22  
  

 

 

  

 

 

  

 

 

  

 

 

 

Operating (loss) income

   (411  105    142    (37

Other income and (deductions)

      

Interest expense, net

   (6  (65  (68  3  

Other, net

   2    (4  9    (13
  

 

 

  

 

 

  

 

 

  

 

 

 

Total other income and (deductions)

   (4  (69  (59  (10
  

 

 

  

 

 

  

 

 

  

 

 

 

(Loss) income before income taxes

   (415  36    83    (47

Income taxes

   (106  17    30    13  
  

 

 

  

 

 

  

 

 

  

 

 

 

Net (loss) income attributable to membership interest/common shareholders

  $(309 $19   $53   $(34
  

 

 

  

 

 

  

 

 

  

 

 

 

(a)

PHI evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. PHI believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and 2014, respectivelymay not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Successor Period March 24, 2016 to March 31, 2016

PHI’s net loss attributable to membership interest for the Successor period of March 24, 2016 to March 31, 2016 was $309 million. There were no significant changes in the underlying trends affecting PHI’s results of operations during the Successor period March 24, 2016 to March 31, 2016 except for the pre-tax recording of $418 million of non-recurring merger-related costs within Operating and maintenance expense.

Predecessor Period January 1, 2016 to March 23, 2016 Compared to the Three Months Ended March 31, 2015

Net Income Attributable to Common Shareholders

PHI’s net income attributable to common shareholders was $19 million for the period January 1, 2016 to March 23, 2016 as compared to $53 million for the three months ended March 31, 2015.

Revenue Net of Purchased Power and Fuel Expense

Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, decreased by $59 million for the period January 1, 2016 to March 23, 2016 as compared to the three months ended March 31, 2015. The decrease is attributable to the following factors:

Decrease of $10 million at Pepco primarily related to electric distribution revenue decreases totaling $14 million due to less days of activity in 2016 compared to 2015 and $4 million lower transmission revenue due to lower days of activity, partially offset by an increase in transmission revenue from an estimated higher rate effective June 1, 2015. These decreases were partially offset by an increase in distribution revenue of $8 million due to an EmPower Maryland rate increase effective February 2015.

Decrease of $22 million at DPL primarily related to electric distribution revenue decreases totaling $13 million and natural gas distribution revenues totaling $7 million due to milder weather and less days of activity in 2016 compared to 2015, a decrease of $3 million associated with the Renewable Portfolio Surcharge in Delaware, partially offset by an increase of $2 million due to an EmPower Maryland rate increase effective February 2015.

Decrease of $14 million at ACE primarily related to milder weather and less days of activity in 2016 compared to 2015.

Decrease of $12 million at PES primarily related to a loss on a construction contract, lower thermal service volumes in 2016 and to less days of activity in 2016 compared to 2015.

Operating and Maintenance Expense

Operating and maintenance expense decreased by $6 million for the period January 1, 2016 to March 23, 2016 as compared to the three months ended March 31, 2015. The decrease is attributable to the following factors:

Decrease of $22 million at Pepco, DPL and ACE primarily due to lower labor, contracting and material costs related to the implementation of a new customer information system in 2015 and less days of activity in 2016 compared to 2015.

Decrease of $6 million at PES primarily due to less days of activity in 2016 compared to 2015 and non-recurring costs incurred in 2015.

Increase of $22 million at Corporate due primarily to Merger-related transaction and integration costs.

Depreciation and Amortization Expense

Depreciation and amortization expense decreased by $3 million primarily due to a decrease of $6 million in the amortization of regulatory assets and lower depreciation of $2 million due to less days of activity in 2016 compared to 2015, partially offset by higher plant balances at all operating companies. These decreases were partially offset by an increase of $6 million associated with the EmPower Maryland surcharge rate increase effective February 2015.

Taxes Other Than Income

Taxes other than income decreased by $13 million primarily due to lower utility taxes that are collected and passed through by Pepco and DPL of $9 million resulting from less days of activity in 2016 compared to 2015 and lower property taxes in Maryland of $4 million.

Interest Expense, Net

Interest expense decreased by $3 million due to lower days of activity in 2016 compared to 2015.

Other, Net

Other, net decreased by $13 million primarily due to the preferred stock derivative expense of $18 million, partially offset by increased income of $3 million from AFUDC equity.

Effective Income Tax Rate

PHI’s effective income tax rates for the period January 1, 2016 to March 23, 2016 and for the three months ended March 31, 2015 were 47.2% and 36.1%, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Results of Operations—Pepco

    Three Months Ended
March 31,
  Favorable
(Unfavorable)
Variance
 
      2016          2015      

Operating revenues

  $551   $545   $6  

Purchased power expense

   197    211    14  
  

 

 

  

 

 

  

 

 

 

Revenue net of purchased power expense(a)

   354    334    20  
  

��

 

  

 

 

  

 

 

 

Other operating expenses

    

Operating and maintenance

   290    113    (177

Depreciation and amortization

   75    62    (13

Taxes other than income

   94    96    2  
  

 

 

  

 

 

  

 

 

 

Total other operating expenses

   459    271    (188
  

 

 

  

 

 

  

 

 

 

Operating (loss) income

   (105  63    (168
  

 

 

  

 

 

  

 

 

 

Other income and (deductions)

    

Interest expense, net

   (37  (30  (7

Other, net

   9    5    4  
  

 

 

  

 

 

  

 

 

 

Total other income and (deductions)

   (28  (25  (3
  

 

 

  

 

 

  

 

 

 

(Loss) income before income taxes

   (133  38    (171

Income taxes

   (25  12    37  
  

 

 

  

 

 

  

 

 

 

Net (loss) income attributable to common shareholder

  $(108 $26   $(134
  

 

 

  

 

 

  

 

 

 

(a)

Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and 4,521 mmcfs ($28 million)may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Net Income Attributable to Common Shareholder

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015.    Pepco’s net income attributable to common shareholder for the three months ended March 31, 2016, was lower than the same period in 2015, primarily due to an increase in Operating and maintenance expense due to merger-related costs.

Operating Revenue Net of Purchased Power Expense

Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation suppliers. The customers’ choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.

Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three months ended March 31, 2016, compared to the same period in 2015, consisted of the following:

    Three Months Ended
March 31,
 
    2016  2015 

Electric

   65  61

Retail customers purchasing electric generation from competitive electric generation suppliers at March 31, 2016 and 2015 consisted of the following:

    March 31, 2016  March 31, 2015 
    Number of
customers
   % of total
retail
customers
  Number
of
customers
   % of total
retail
customers
 

Electric

   173,221     21  166,127     20

Retail deliveries purchased from competitive electric generation suppliers represented 73% of Pepco’s retail kWh sales to the District of Columbia customers and 58% of Pepco’s retail kWh sales to Maryland customers for the three months ended March 31, 2016 and 67% of Pepco’s retail kWh sales to the District of Columbia customers and 56% of Pepco’s retail kWh sales to Maryland customers for the three months ended March 31, 2015.

The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

The changes in Pepco’s operating revenues net of purchased power expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

    Increase (Decrease) 

Volume

  $5  

Regulatory required programs

   13  

Transmission revenue

   2  
  

 

 

 

Total increase (decrease)

  $20  
  

 

 

 

Revenue Decoupling.    Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the

District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in Pepco’s service territory. The changes in heating and cooling degree days in Pepco’s service territory for the three months ended March 31, 2016 compared to the same period in 2015 and normal weather consisted of the following:

    Three Months Ended
March 31,
   Normal   % Change 

Heating and Cooling Degree-Days

      2016           2015         2016 vs. 2015  2016 vs. Normal 

Heating Degree-Days

   2,010     2,491     2,170     (19.3)%   (7.4)% 

Cooling Degree-Days

   3          3     n/a    

Volume.    The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three months ended March 31, 2016 compared to the same period in 2015, primarily reflects the impact of moderate economic and customer growth.

Regulatory Required Programs.    This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.

Transmission Revenue.    Transmission revenue increased as a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by a higher reserve related to the FERC ROE settlement.

Operating and Maintenance Expense

    Three Months Ended
March 31,
   Increase
(Decrease)
 
        2016           2015       

Operating and maintenance expense — baseline

  $287    $110    $177  

Operating and maintenance expense — regulatory required programs(a)

   3     3       
  

 

 

   

 

 

   

 

 

 

Total operating and maintenance expense

  $290    $113    $177  
  

 

 

   

 

 

   

 

 

 

(a)

Operating and 7,508 mmcfs ($60 million)maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

The changes in operating and maintenance expense for the three months ended March 31, 2016 compared to the same period in 2015, consisted of the following:

    Increase (Decrease) 

Baseline

  

Labor, other benefits, contracting and materials

  $7  

Storm-related costs

   2  

BSC and PHISCO allocations(a)

   29  

Merger commitments(b)

   139  
  

 

 

 

Total increase (decrease)

  $177  
  

 

 

 

(a)

Primarily related to merger severance and compensation costs.

(b)

Primarily related to merger-related commitments for customer rate credits and charitable contributions.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

    Increase (Decrease) 

Depreciation expense(a)

  $2  

Regulatory asset amortization(b)

   11  
  

 

 

 

Total increase (decrease)

  $13  
  

 

 

 

(a)

Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization increased for the ninethree months ended September 30,March 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015.

Taxes Other Than Income

Taxes other than income for the three months ended March 31, 2016 compared to the same period in 2015 decreased primarily due to lower property taxes in Maryland.

Interest Expense, Net

Interest expense, net for the three months ended March 31, 2016 compared to the same period in 2015 increased $7 million primarily due to the recording of interest expense for an uncertain tax position in 2016.

Other, Net

Other, net for the three months ended March 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC.

Effective Income Tax Rate

Pepco’s effective income tax rate was 18.8% and 31.6% for the three months ended March 31, 2016 and 2015, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. As a result of the merger, Pepco recorded an after-tax charge of $33 million during the three months ended March 31, 2016 as a result of assessment and remeasurement of certain federal and state uncertain tax positions.

Pepco Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,
   % Change  Weather -
Normal
% Change
 

Retail Deliveries to Customers (in GWhs)

  2016   2015    

Retail Deliveries(a)

       

Residential

   2,218     2,590     (14.4)%   (3.5)% 

Small commercial & industrial

   381     464     (17.9)%   (1.5)% 

Large commercial & industrial

   3,945     3,607     9.4  (0.7)% 

Public authorities & electric railroads

   189     185     2.2  (0.4)% 
  

 

 

   

 

 

    

Total retail deliveries

   6,733     6,846     (1.7)%   (1.7)% 
  

 

 

   

 

 

    
   As of March 31,        

Number of Electric Customers

  2016   2015        

Residential

   769,934     739,321     

Small commercial & industrial

   53,853     53,303     

Large commercial & industrial

   20,996     20,102     

Public authorities & electric railroads

   126     126     
  

 

 

   

 

 

    

Total

   844,909     812,852     
  

 

 

   

 

 

    
   Three Months Ended
March 31,
   % Change    

Electric Revenue

  2016   2015      

Retail Sales(a)

       

Residential

  $255    $261     (2.3)%  

Small commercial & industrial

   37     41     (9.8)%  

Large commercial & industrial

   200     187     7.0 

Public authorities & electric railroads

   8     8      
  

 

 

   

 

 

    

Total retail

   500     497     0.6 
  

 

 

   

 

 

    

Other revenue(b)

   51     48     6.3 
  

 

 

   

 

 

    

Total electric revenue

  $551    $545     1.1 
  

 

 

   

 

 

    

(a)

Reflects delivery volumes and 2014,revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission.

(b)

Other revenue includes transmission revenue from PJM and wholesale electric revenues.

Results of Operations — DPL

  Three Months Ended
March 31,
  Favorable
(Unfavorable)
Variance
 
  2016  2015  

Operating revenues

 $362   $421   $(59

Purchased power and fuel

  176    225    49  
 

 

 

  

 

 

  

 

 

 

Revenue net of purchased power and fuel(a)

  186    196    (10
 

 

 

  

 

 

  

 

 

 

Other operating expenses

   

Operating and maintenance

  204    81    (123

Depreciation and amortization

  39    39      

Taxes other than income

  15    13    (2
 

 

 

  

 

 

  

 

 

 

Total other operating expenses

  258    133    (125
 

 

 

  

 

 

  

 

 

 

Operating (loss) income

  (72  63    (135
 

 

 

  

 

 

  

 

 

 

Other income and (deductions)

   

Interest expense, net

  (12  (12    

Other, net

  3    2    1  
 

 

 

  

 

 

  

 

 

 

Total other income and (deductions)

  (9  (10  1  
 

 

 

  

 

 

  

 

 

 

(Loss) income before income taxes

  (81  53    (134

Income taxes

  (9  21    30  
 

 

 

  

 

 

  

 

 

 

Net (loss) income attributable to common shareholder

 $(72 $32   $(104
 

 

 

  

 

 

  

 

 

 

(a)

DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Net Income Attributable to Common Shareholder

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015.    The decrease in net income attributable to common shareholder was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.

Operating Revenues Net of Purchased Power and Fuel Expense

Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric and gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.

Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three months ended March 31, 2016 and 2015, consisted of the following:

   Three Months Ended
March 31,
 
   2016  2015 

Electric

   49  41

Natural Gas

   25  23

Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at March 31, 2016 and 2015 consisted of the following:

   March 31, 2016  March 31, 2015 
   Number of
customers
   % of total retail
customers
  Number of
customers
   % of total retail
customers
 

Electric

   77,014     14.9  76,706     14.9

Natural Gas

   158     0.1  160     0.1

Retail deliveries purchased from competitive electric generation suppliers represented 51% of DPL’s retail kWh sales to Delaware customers and 44% of DPL retail kWh sales to Maryland customers for the three months ended March 31, 2016 and 42% to Delaware customers and 39% to Maryland customers for the three months ended March 31, 2015.

The costs related to default electricity supply are included in Purchased power and fuel. Operating revenues also include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.

Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Natural Gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Purchased power consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales.

The changes in DPL’s operating revenues net of purchased power and fuel expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

   Increase (Decrease) 
   Electric  Gas  Total 

Weather

  $(7 $(8 $(15

Volume

   2    2    4  

Regulatory required programs

   (1      (1

Transmission revenue

   3        3  

Other

   (1      (1
  

 

 

  

 

 

  

 

 

 

Total increase (decrease)

  $(4 $(6 $(10
  

 

 

  

 

 

  

 

 

 

Revenue Decoupling.    DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

Weather.    The demand for electricity and gas in areas not subject to the BSA is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and gas. Conversely, mild weather reduces demand. During the three months ended March 31, 2016 compared to the same period in 2015, operating revenues net of purchased power and fuel expense was lower due to the impact of unfavorable winter weather conditions in DPL’s service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL’s electric service territory and a 30-year period in DPL’s gas service territory. The changes in heating and cooling degree days in DPL’s service territory for the three months ended March 31, 2016 compared to the same period in 2015 and normal weather consisted of the following:

   Three Months Ended
March 31,
       % Change 

Heating and Cooling Degree-Days

      2016           2015       Normal   2016 vs. 2015  2016 vs. Normal 

Heating Degree-Days

   2,247     2,865     2,449     (21.6)%   (8.2)% 

Cooling Degree-Days

   3          1     n/a    200.0

Volume.    The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three months ended March 31, 2016 compared to the same period in 2015, primarily reflects the impact of moderate economic and customer growth.

Regulatory Required Programs.    This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the operating and maintenance expense discussion below for additional information on included programs.

Transmission Revenue.    Transmission revenue increased as a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by a higher reserve related to the FERC ROE settlement.

Operating and Maintenance Expense

   Three Months Ended
March 31,
   Increase
(Decrease)
 
   2016   2015   

Operating and maintenance expense — baseline

  $201    $76    $125  

Operating and maintenance expense — regulatory required programs(a)

   3     5     (2
  

 

 

   

 

 

   

 

 

 

Total operating and maintenance expense

  $204    $81    $123  
  

 

 

   

 

 

   

 

 

 

(a)

Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

The changes in operating and maintenance expense for the three months ended March 31, 2016 compared to the same period in 2015, consisted of the following:

   Increase (Decrease) 

Baseline

  

Labor, other benefits, contracting and materials

  $1  

Storm-related costs

   3  

Pension and non-pension postretirement benefits expense

   1  

Uncollectible accounts expense

   (1

BSC and PHISCO allocations(a)

   16  

Merger commitments(b)

   104  

Other

   1  
  

 

 

 
   125  

Regulatory required programs

  

Purchased power administrative costs

   (2
  

 

 

 

Total increase (decrease)

  $123  
  

 

 

 

(a)

Primarily related to merger severance and compensation costs.

(b)

Primarily related to merger-related commitments for customer rate credits and charitable contributions.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

   Increase (Decrease) 

Depreciation expense(a)

  $2  

Regulatory asset amortization(b)

   2  

Delaware renewable energy portfolio standards deferral

   (4
  

 

 

 

Total increase (decrease)

  $  
  

 

 

 

(a)

Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization increased for the three months ended March 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015.

Taxes Other Than Income

Taxes other than income for the three months ended March 31, 2016 compared to the same period in 2015 remained relatively consistent.

Interest Expense, Net

Interest expense, net for the three months ended March 31, 2016 compared to the same period in 2015 remained relatively constant.

Other, Net

Other, net for the three months ended March 31, 2016 remained relatively level compared to the same period in 2015.

Effective Income Tax Rate

DPL’s effective income tax rate was 11.1% and 39.6% for the three months ended March 31, 2016 and 2015, respectively. See Note 11 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, DPL recorded an after-tax charge of $24 million during the three months ended March 31, 2016 as a result of assessment and remeasurement of certain federal and state uncertain tax positions.

DPL Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,
   % Change  Weather -
Normal  %
Change
 

Retail Deliveries to Customers (in GWhs)

      2016           2015        

Retail Deliveries(a)

       

Residential

   1,428     1,863     (23.3)%   (4.8)% 

Small commercial & industrial

   572     510     12.2  (1.7)% 

Large commercial & industrial

   1,078     1,108     (2.7)%   (0.8)% 

Public authorities & electric railroads

   14     13     7.7  
  

 

 

   

 

 

    

Total retail deliveries

   3,092     3,494     (11.5)%   (2.9)% 
  

 

 

   

 

 

    
   As of March 31,        

Number of Electric Customers

  2016   2015        

Residential

   453,670     451,299     

Small commercial & industrial

   59,860     60,486     

Large commercial & industrial

   1,418     1,287     

Public authorities & electric railroads

   643     582     
  

 

 

   

 

 

    

Total

   515,591     513,654     
  

 

 

   

 

 

    
   Three Months Ended
March 31,
   % Change    

Electric Revenue

  2016   2015    

Retail Sales(a)

       

Residential

  $182    $217     (16.1)%  

Small commercial & industrial

   49     51     (3.9)%  

Large commercial & industrial

   25     23     8.7 

Public authorities & electric railroads

   4     3     33.3 
  

 

 

   

 

 

    

Total retail

   260     294     (11.6)%  
  

 

 

   

 

 

    

Other revenue(b)

   43     41     4.9 
  

 

 

   

 

 

    

Total electric revenue

  $303    $335     (9.6)%  
  

 

 

   

 

 

    

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.

(b)

Other revenue includes transmission revenue from PJM and wholesale electric revenues.

DPL Gas Operating Statistics and Revenue Detail

   Three Months Ended
March 31,
   % Change  Weather -
Normal
% Change
 

Retail Deliveries to Customers (in mmcf)

      2016           2015        

Retail Deliveries

       

Residential

   6,060     7,878     (23.1)%   (7.3)% 

Transportation & other

   1,968     2,325     (15.4)%   (2.4)% 
  

 

 

   

 

 

    

Total gas deliveries

   8,028     10,203     (21.3)%   (6.1)% 
  

 

 

   

 

 

    
   As of March 31,        

Number of Gas Customers

  2016   2015        

Residential

   120,046     118,549     

Commercial & industrial

   9,772     9,556     

Transportation & other

   158     160     
  

 

 

   

 

 

    

Total

   129,976     128,265     
  

 

 

   

 

 

    
   Three Months Ended
March 31,
   % Change    

Gas Revenue

  2016   2015    

Retail Sales(a)

       

Retail sales

  $53    $79     (32.9)%  

Transportation & other(b)

   6     7     (14.3)%  
  

 

 

   

 

 

    

Total gas revenues

  $59    $86     (31.4)%  
  

 

 

   

 

 

    

(a)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.

(b)

Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

Results of Operations — ACE

   Three Months Ended
March 31,
  Favorable
(Unfavorable)
Variance
 
   2016  2015  

Operating revenues

  $291   $334   $(43

Purchased power expense

   158    191    33  
  

 

 

  

 

 

  

 

 

 

Revenue net of purchased power expense(a)

   133    143    (10
  

 

 

  

 

 

  

 

 

 

Other operating expenses

    

Operating and maintenance

   212    69    (143

Depreciation and amortization

   40    43    3  

Taxes other than income

   2    2      
  

 

 

  

 

 

  

 

 

 

Total other operating expenses

   254    114    (140
  

 

 

  

 

 

  

 

 

 

Operating (loss) income

   (121  29    (150
  

 

 

  

 

 

  

 

 

 

Other income and (deductions)

    

Interest expense, net

   (16  (16    

Other, net

   4    1    3  
  

 

 

  

 

 

  

 

 

 

Total other income and (deductions)

   (12  (15  3  
  

 

 

  

 

 

  

 

 

 

(Loss) income before income taxes

   (133  14    (147

Income taxes

   (33  5    38  
  

 

 

  

 

 

  

 

 

 

Net (loss) income attributable to common shareholder

  $(100 $9   $(109
  

 

 

  

 

 

  

 

 

 

(a)

ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

Net Income Attributable to Common Shareholder

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015.    The decrease in net income attributable to common shareholder was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.

Operating Revenue Net of Purchased Power Expense

Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer’s choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.

Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three months ended March 31, 2016, compared to the same period in 2015, consisted of the following:

   Three Months Ended
March 31,
 
   2016  2015 

Electric

   47  43

Retail customers purchasing electric generation from competitive electric generation suppliers at March 31, 2016 and 2015 consisted of the following:

   March 31, 2016  March 31, 2015 
   Number of
customers
   % of total
retail
customers
  Number of
customers
   % of total
retail
customers
 

Electric

   73,165     13  79,524     15

The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM RTO market of energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.

Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

The changes in ACE’s operating revenues net of purchased power expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

   Increase (Decrease) 

Weather

  $(7

Regulatory required programs

   (5

Transmission revenues

   3  

Other

   (1
  

 

 

 

Total increase (decrease)

  $(10
  

 

 

 

Weather.    The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three months ended March 31, 2016 compared to the same period in 2015, operating revenues net of purchased power and fuel expense was lower due to the impact of unfavorable winter weather conditions in ACE’s service territory.

For retail customers of ACE, distribution revenues are not decoupled for the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE’s service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

   Three Months Ended
March 31,
   Normal   % Change 

Heating and Cooling Degree-Days

      2016           2015         2016 vs. 2015  2016 vs. Normal 

Heating Degree-Days

   2,270     3,041     2,523     (25.4)%   (10.0)% 

Cooling Degree-Days

   4          1     n/a    300.0

Regulatory Required Programs.    This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in operating and maintenance expense, depreciation and amortization expense and income taxes. Refer to the depreciation and amortization expense discussion below for additional information on included programs.

Transmission Revenue.    Transmission revenue increased as a result of higher rates effective June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by a higher reserve related to the FERC ROE settlement.

Operating and Maintenance Expense

   Three Months Ended
March 31,
   Increase
(Decrease)
 
   2016   2015   

Operating and maintenance expense — baseline

  $211    $68    $143  

Operating and maintenance expense — regulatory required programs(a)

   1     1       
  

 

 

   

 

 

   

 

 

 

Total operating and maintenance expense

  $212    $69    $143  
  

 

 

   

 

 

   

 

 

 

(a)

Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

The changes in operating and maintenance expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

   Increase (Decrease) 

Baseline

  

Labor, other benefits, contracting and materials

  $12  

BSC and PHISCO allocations(a)

   13  

Uncollectible accounts expense

   2  

Merger commitments(b)

   120  

Other

   (4
  

 

 

 

Total increase (decrease)

  $143  
  

 

 

 

(a)

Primarily related to merger severance and compensation costs.

(b)

Primarily related to merger-related commitments for customer rate credits and charitable contributions.

Depreciation and Amortization Expense

The changes in depreciation and amortization expense for the three months ended March 31, 2016 compared to the same period in 2015 consisted of the following:

   Increase (Decrease) 

Depreciation expense(a)

  $1  

Regulatory asset amortization(b)

   (4
  

 

 

 

Total increase (decrease)

  $(3
  

 

 

 

(a)

Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization decreased for the three months ended March 31, 2016 compared to the same period in 2015 as a result of lower revenue due to a rate decrease effective October 2015 for the ACE Market Transition charge tax.

Taxes Other Than Income

Taxes other than income for the three months ended March 31, 2016 compared to the same period in 2015, remained relatively constant.

Interest Expense, Net

Interest expense, net for the three months ended March 31, 2016 compared to the same period in 2015 remained relatively constant.

Other, Net

Other, net for the three months ended March 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC equity.

Effective Income Tax Rate

ACE’s effective income tax rate was 24.8% and 35.7%, for the three months ended March 31, 2016 and 2015, respectively. See Note 11—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. As a result of the merger, ACE recorded an after-tax charge of $23 million during the three months ended March 31, 2016 as a result of assessment and remeasurement of certain federal uncertain tax positions.

ACE Electric Operating Statistics and Revenue Detail

   Three Months Ended
March 31,
   % Change  Weather  -
Normal
%
Change
 

Retail Deliveries to Customers (in GWhs)

      2016           2015        

Retail Deliveries(a)

       

Residential

   938     1,124     (16.5)%   (3.5)% 

Small commercial & industrial

   289     305     (5.2)%   (1.7)% 

Large commercial & industrial

   820     816     0.5  (1.0)% 

Public authorities & electric railroads

   15     12     25.0  
  

 

 

   

 

 

    

Total retail deliveries

   2,062     2,257     (8.6)%   (2.2)% 
  

 

 

   

 

 

    
   As of March 31,        

Number of Electric Customers

  2016   2015        

Residential

   482,718     481,354     

Small commercial & industrial

   60,858     61,030     

Large commercial & industrial

   3,828     3,814     

Public authorities & electric railroads

   583     553     
  

 

 

   

 

 

    

Total

   547,987     546,751     
  

 

 

   

 

 

    
   Three Months Ended
March 31,
   % Change    

Electric Revenue

      2016           2015        

Retail Sales(a)

       

Residential

  $150    $175     (14.3)%  

Small commercial & industrial

   39     40     (2.5)%  

Large commercial & industrial

   51     49     4.1 

Public authorities & electric railroads

   3     3      
  

 

 

   

 

 

    

Total retail

   243     267     (9.0)%  
  

 

 

   

 

 

    

Other revenue(b)

   48     67     (28.4)%  
  

 

 

   

 

 

    

Total electric revenue

  $291    $334     (12.9)%  
  

 

 

   

 

 

    

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission.

(b)

Other revenue includes transmission revenue from PJM and wholesale electric revenues.

Liquidity and Capital Resources

Exelon’s and Generation’s prior yearExelon activity presented below includes the activity of CENGPHI, Pepco, DPL and ACE, from the integrationPHI Merger effective date effective April 1, 2014of March 24, 2016 through DecemberMarch 31, 2014.2016. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI’s activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the three months ended March 31, 2016 and 2015. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expendituresexpenditure requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s

access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, Exelon Corporate, Generation, ComEd, PECO and BGEthe Registrants have access to syndicated unsecured revolving credit facilities with aggregate bank commitments of $0.5 billion, $5.3 billion, $1.0 billion, $0.6 billion and $0.6 billion, respectively. Exelon Corporate, Generation, ComEd, PECO and BGE’s syndicated revolving credit facilities expire in 2018 and 2019.$9.5 billion. In addition, Generation has $0.5 billion$425 million in bilateral credit facilities with banks which have various expirationexpirations dates between December 20152016 and October 2017.January 2019. The Registrants utilize their credit facilities to support their commercial paper programs, and provide for other short-term borrowings, term loans and issue letters of credit. See the “Credit Matters” section below for further discussion. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and BGEACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1110 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussion of the Registrants’ debt and credit agreements.

PHI Merger Financing

Exelon funded the all-cash purchase price, acquisition and integration related costs, and merger commitments with the issuance of $4.2 billion of debt (of which $3.3 billion remains after execution of the exchange offer), $1.15 billion of junior subordinated notes in the form of 23 million equity units, and $1.9 billion of common stock, cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion) and cash on hand and/or short-term borrowings available to Exelon. See Note 14 —Debt and Credit Agreements and Note 19 — Shareholder’s Equity included in the Exelon 2015 Form 10-K for further information on the debt and equity issuances.

Cash Flows from Operating Activities

General

Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.

ComEd’s, PECO’s and BGE’sThe Utility Registrants’ cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and BGE,DPL, gas distribution services. ComEd’s, PECO’s and BGE’sThe Utility Registrants’ distribution services are provided to an established and diverse base of retail customers. ComEd’s, PECO’s and BGE’sThe Utility Registrants’ future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions.

See NoteNotes 3 — Regulatory Matters and Note 2223 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 20142015 Form 10-K for further discussion of regulatory and legal proceedings and proposed legislation. See Note 7—Regulatory Matters and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the PHI 2015 Form 10-K.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the three months ended March 31, 2016 and 2015:

   Three Months Ended
March  31,
  Variance 
        2016(c)          2015      

Net income

  $123   $738   $(615

Add (subtract):

    

Non-cash operating activities(a)

   1,942    1,282    660  

Pension and other postretirement benefit contributions

   (239  (269  30  

Income taxes

   47    174    (127

Changes in working capital and other noncurrent assets and liabilities(b)

   (623  (697  74  

Option premiums received, net

   17    5    12  

Counterparty collateral posted, net

   206    257    (51
  

 

 

  

 

 

  

 

 

 

Net cash flows provided by operations

  $1,473   $1,490   $(17
  

 

 

  

 

 

  

 

 

 

(a)

Represents, when applicable, depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, PHI merger commitment and severance charges, and other non-cash charges. See Note 19—Supplemental Financial Information for further detail on non-cash operating activity.

(b)

Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

(c)

Includes PHI Consolidated activity from March 24, 2016 to March 31, 2016.

Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, and management of the net pension obligation and regulatory implications. On July 6, 2012, President Obama signed into law the Moving Ahead for Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near term while increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. Certain provisions of the law were applied in 2012 while the others took effect in 2013. On August 8, 2014, this funding relief was extended for five years. The estimated impacts ofOn November 2, 2015 the law are reflected in Exelon’s projectedfunding relief was extended for an additional three years and premiums pension contributions.plans pay to the Pension Benefit Guaranty Corporation were further increased.

OPEB funding generally follows accounting cost, subject to adjustment for other considerations such as liabilities management and regulatory implications.

To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase, especially in years 2018 and beyond.increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

Tax Matters

The Registrants’ future cash flows from operating activities may be affected by the following tax matters:

 

In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon would be required to either post a bond or pay the tax and interest for the tax years before the court to appeal the decision. If an adverse decision is reached in 2016, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable as of September 30, 2015 may be as much as $820$865 million, of which approximately $300 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. Exelonharmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity, and the

 

expects to deposit approximately $260 million related to the termination ofbalance at Exelon. It is expected that Exelon’s investment in one of the three like-kind exchange properties within the next twelve months. Interest will continue to accrue until such time as payment is made. An appeal of an adverse decision in the Tax Court would necessitate either the posting of a bond or the payment of the tax and interest for theremaining tax years beforeaffected by the court. Alitigation will be settled following a final appellate decision which could take several years.

 

In April of 2016, Exelon Generation, and ComEd expect to receivereceived tax refunds of approximately $430 million, $195 million, and $265 million, respectively, in 2015. PECO expects to make tax payments of approximately $7$460 million related to IRS positions settlingsettled in 2015.prior tax years. Of this amount, approximately $195 million of the refund is attributable to Generation and the remaining $265 million is attributable to ComEd.

 

State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax levies, property taxes and other taxes or the imposition, extension or permanence of temporary tax levies.

The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the nine months ended September 30, 2015 and 2014:

   Nine Months Ended
September 30,
    
   2015(c)  2014  Variance 

Net income

  $1,959   $1,725   $234  

Add (subtract):

    

Non-cash operating activities(a)

   3,900    4,200    (300

Gain on consolidation and acquisitions of businesses

       (268  268  

Pension and other postretirement benefit contributions

   (430  (516  86  

Income taxes

   300    72    228  

Changes in working capital and other noncurrent assets and liabilities(b)

   (387  (976  589  

Option premiums received, net

   27    21    6  

Counterparty collateral received (posted), net

   305    (615  920  
  

 

 

  

 

 

  

 

 

 

Net cash flows provided by operations

  $5,674   $3,643   $2,031  
  

 

 

  

 

 

  

 

 

 

(a)

Represents depreciation, amortization and accretion, impairment of long-lived assets, mark-to-market gains and losses on derivative transactions, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense and other non-cash charges.

(b)

Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

(c)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 activity includes CENG on a fully consolidated basis.

Cash flows from operations for the ninethree months ended September 30,March 31, 2016 and 2015 and 2014 by Registrant were as follows:

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
  2015   2014       2016           2015     

Exelon(a)

  $5,674    $3,643    $1,473    $1,490  

Generation(a)

   3,206     1,784     782     837  

ComEd

   1,346     849     284     251  

PECO

   567     504     138     158  

BGE

   696     625     273     281  

Pepco

   258     33  

DPL

   147     57  

ACE

   246     63  

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 activity includes CENG on a fully consolidated basis.

  Successor     Predecessor 
  March 24, 2016 to
March 31, 2016
     January 1, 2016 to
March 23, 2016
   Three Months Ended
March 31, 2015
 

PHI

 $43     $264    $157  

Changes in Exelon’s, Generation’s, ComEd’s, PECO’s and BGE’sthe Registrants’ cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the ninethree months ended September 30,March 31, 2016 and 2015 and 2014 were as follows:

Generation

 

Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on the exchange or in the OTC markets. During the ninethree months ended September 30,March 31, 2016 and 2015, and 2014, Generation had net collections/(payments)collections of counterparty cash collateral of $376$198 million and $(634)$288 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

 

During the ninethree months ended September 30,March 31, 2016 and 2015, and 2014, Generation had net collections of approximately $27$17 million and $21$5 million, respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

ComEd

 

During the ninethree months ended September 30,March 31, 2016 and 2015, ComEd received a return of approximately $7 million of cash collateral from PJM and 2014, ComEd’s payables for Generation energy purchases decreased by $(20) million and $(38) million, respectively, and payables to other energy suppliers for energy purchases increased byposted $5 million and $58 million, respectively.

During the nine months ended September 30, 2015 and 2014, ComEd posted $41 million and $1 million of cash collateral to PJM, respectively. ComEd’s collateral posted with PJM has increased year over year primarily due to higher RPM credit requirements and higher PJM billings resulting from increased load being served bybillings. As of March 31, 2016 and 2015, ComEd as a result of City of Chicago customers switching back to ComEd.

PECO

During the nine months ended September 30, 2015 and 2014, PECO’s payables to Generation for energy purchases increased/(decreased) by $4had approximately $24 million and $(17)$5 million respectively, and payables to other electric and gas suppliers for energy purchases decreased by $(21) million and $(12) million,of cash collateral posted with PJM, respectively.

BGE

During the nine months ended September 30, 2015 and 2014, BGE’s payables to Generation for energy purchases increased/(decreased) by $(13) million and $7 million, respectively, and payables to other electric and gas suppliers for energy purchases decreased by $(25) million and $(27) million, respectively.

Cash Flows from Investing Activities

Cash flows used in investing activities for the ninethree months ended September 30,March 31, 2016 and 2015 and 2014 by Registrant were as follows:

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
  2015   2014   2016   2015 

Exelon(a)

  $(5,689  $(3,376  $(8,548  $(1,751

Generation(a)

   (3,020   (1,431   (1,204   (899

ComEd

   (1,646   (1,148   (626   (523

PECO

   (425   (452   (351   (144

BGE

   (491   (480   (191   (132

Pepco

   (136   (113

DPL

   (81   (61

ACE

   (100   (53

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 activity includes CENG on a fully consolidated basis.

   Successor      Predecessor 
   March 24, 2016 to
March 31, 2016
      January 1, 2016 to
March 23, 2016
  Three Months Ended
March 31, 2015
 

PHI

  $(30    $(343 $(235

Generation

Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies. The agreements contain a series of scheduled investment commitments, including in-kind service contributions. There are approximately $346$299 million of anticipated expenditures remaining through 20192018 to fund anticipated planned capital and operating needs of the associated companies.

Generation has executed, or expects See Note 23 — Commitments and Contingencies of the Combined Notes to execute, several construction and services contracts. AsConsolidated Financial Statements of September 30,the Exelon 2015 the total estimated remaining construction expendituresForm 10-K for these projects are approximately $1.3 billion and achievementfurther details of commercial operations is expected between 2015 and 2018 for all these projects.Generation’s equity interests.

Capital expenditures by Registrant for the ninethree months ended September 30,March 31, 2016 and 2015 and 2014 and projected amounts for the full year 20152016 are as follows:

 

  Projected
Full Year
2015(e)
   Nine Months Ended
September 30,
   Projected
Full Year
2016(a)
   Three Months Ended
March 31,
 
  2015   2014    2016   2015 

Exelon(a)

  $7,600    $5,443    $4,114    $9,375    $2,202    $1,784  

Generation(a)(b)

   3,850     2,774     1,961  

Generation(b)

   3,600     1,125     937  

ComEd(c)

   2,425     1,670     1,173     2,525     639     530  

PECO

   600     435     461     675     195     148  

BGE

   675     506     458     850     176     136  

Pepco

   725     109     119  

DPL

   350     81     68  

ACE

   325     101     54  

Other(d)

   50     58     61     150     38     38  

   Projected
Full Year
2016(a)
   Successor      Predecessor 
    March 24, 2016
to March 31,
2016
      January 1, 2016
to March 23,
2016
   Three Months
Ended March 31,
2015
 

PHI

  $1,400    $29      $273    $246  

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, CENG is included on a fully consolidated basis in the 2015 results above.Total projected capital expenditures do not include adjustments for non-cash activity.

(b)

Generation’s capital expenditures for the projected full year 20152016 includes nuclear fuel (NE fleet at 100%) of $1.3$1.1 billion and growth expenditures of $1.2$1.4 billion.

(c)

The projected capital expenditures2016 projections include approximately $665$623 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten year period, through 2022, to modernize and storm-harden its distribution system and to implement smart grid technology.

(d)

Other primarily consists of corporate operations, BSC and BSC.

(e)

Total projected capital expenditures do not include adjustments for non-cash activity.PHISCO.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

In 2014, Exelon and its affiliates initiated a comprehensive project to ensure corporate-wide compliance with Version 5 of the North American Electric Reliability Corporation (NERC) Critical Infrastructure Protection Standards (CIP V.5) which will become effective on April 1, 2016. Generation, ComEd, PECO and BGE will be incurring incremental capital expenditures through 2016 associated with the CIP V.5 compliance implementation project.

Generation

Approximately 35%31% and 5%15% of the projected 20152016 capital expenditures at Generation are for the acquisition of nuclear fuel and investments in renewable energy andthe construction of new natural gas electric generation plants, respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.

ComEd, PECO, BGE, Pepco, DPL and BGEACE

Approximately 84%86%, 96%, 97%, 93%, 91% and 95%92% of the projected 20152016 capital expenditures at ComEd, PECO, BGE, Pepco, DPL and BGE,ACE, respectively, are for continuing projects to maintain and improve operations, including enhancing reliability and

adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and ComEd’s, PECO’s and BGE’sthe Utility Registrants��� construction commitments under PJM’s RTEP. In addition to the capital expenditureexpenditures for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA and for PECO, BGE, Pepco, DPL, and BGE, totalACE capital expenditures related to their respective smart meter program.

The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommends ComEd, PECO and BGErecommended the Utility Registrants perform assessments of all their transmission lines. In compliance with this guidance, ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 20152016 capital expenditures above reflect capital spending in 2015 for remediation to be completed through 2017. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidance in 2016.

ComEd, PECO and BGEThe Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

Cash Flows from Financing Activities

Cash flows provided by (used in) financing activities for the ninethree months ended September 30,March 31, 2016 and 2015 and 2014 by Registrant were as follows:

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
  2015   2014       2016           2015     

Exelon(a)

  $5,402    $887    $1,533    $208  

Generation(a)

   (421   (300   368     (186

ComEd

   285     307     296     314  

PECO

   (140   77     (69   (6

BGE

   (242   (149   (86   (172

Pepco

   (103   200  

DPL

   (68   7  

ACE

   (27   (6

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 activity includes CENG on a fully consolidated basis.

PHI Merger Financing

As of September 30, 2015, through the issuance of $5.4 billion of debt (including $1.15 billion of junior subordinated notes in the form of 23 million equity units), the issuance of $1.9 billion of common stock, and cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion), Exelon has sufficient cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments. See Note 11—Debt and Credit Agreements and Note 17—Common Stock for further information on the debt and equity issuances. See Note 4—Merger and Acquisitions of the Exelon 2014 Form 10-K for further information on the asset sales.

   Successor      Predecessor 
   March 24, 2016 to
March 31, 2016
      January 1, 2016 to
March 23, 2016
   Three Months Ended
March 31, 2015
 

PHI

  $(181    $372    $205  

Debt

See Note 1110 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’ debt issuances and retirements.

Dividends

Cash dividend payments and distributions during the ninethree months ended September 30,March 31, 2016 and 2015 and 2014 by Registrant were as follows:

 

  Nine Months Ended
September 30,
   Three Months Ended
March 31,
 
  2015   2014       2016           2015     

Exelon(a)

  $819    $1,214    $287    $269  

Generation(a)

   2,368     855     55     1,356  

ComEd

   226     230     91     75  

PECO

   209     240     69     70  

BGE(b)(a)

   126     10     48     39  

Pepco

   39       

DPL

   38     62  

ACE

   11     12  

   Successor      Predecessor 
   March 24, 2016  to
March 31, 2016
      January 1, 2016 to
March 23, 2016
   Three Months Ended
March 31, 2015
 
 

PHI

  $108      $    $68  

 

(a)

On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2015 activity includes CENG on a fully consolidated basis.

(b)

Includes dividends paid on BGE’s preference stock.

First Quarter 2015 Dividend

On January 27, 2015,

Quarterly dividends declared by the Exelon Board of Directors declared a first quarter 2015 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable onduring the three months ended March 10, 2015, to shareholders of record of Exelon at31, 2016 and for the end of the day on February 13, 2015.

Second Quarter 2015 Dividend

On April 28, 2015, the Exelon Board of Directors declared a second quarter 2015 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on June 10, 2015, to shareholders of record of Exelon at the end of the day on May 15, 2015.2016 were as follows:

Third Quarter 2015 Dividend

Period

  

Declaration Date

  

Shareholder of Record Date

  

Dividend Payable Date

  Cash per  Share(a) 

First Quarter 2016

  January 26, 2016  February 12, 2016  March 10, 2016  $0.310  

Second Quarter 2016

  April 26, 2016  May 13, 2016  June 10, 2016  $0.318  

On July 28, 2015, the Exelon Board of Directors declared a third quarter 2015 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on September 10, 2015, to shareholders of record of Exelon at the end of the day on August 14, 2015.

Fourth Quarter 2015 Dividend

On October 27, 2015, the Exelon Board of Directors declared a third quarter 2015 regular quarterly dividend of $0.31 per share on Exelon’s common stock payable on December 10, 2015, to shareholders of record of Exelon at the end of the day on November 13, 2015.
(a)

Exelon’s Board of Directors approved a revised dividend policy. The approved policy would raise the dividend 2.5% each year for the next three years, beginning with the June 2016 dividend. The Board will take formal action to declare the next dividend in the second quarter of 2016.

Short-Term Borrowings

DuringShort-term borrowings incurred (repaid) during the ninethree months ended September 30,March 31, 2016 and 2015 ComEd and BGE issued (repaid) $300 million and $(70) million of commercial paper, respectively, and Generation issued $15 million in short-term notes payable. During the nine months ended September 30, 2014, ComEd and BGE issued (repaid) $344 million and $(115) million of commercial paper, respectively, and Generation repaid $8 million in short-term notes payable.by Registrant were as follows:

   Three Months Ended
March  31,
 
       2016           2015     

Exelon

  $1,647    $(141

Generation

   1,377     (1

ComEd

   349     (21

BGE

   (60   (120

Pepco

   (64   (104

DPL

   (30   69  

ACE

   (5   16  

  Successor    Predecessor 
  March 24, 2016 to
March 31, 2016
    January 1, 2016 to
March 23, 2016
   Three Months Ended
March 31, 2015
 

PHI

 $(20  $379    $74  

Contributions from Parent/Member

DuringContributions received from Parent for the ninethree months ended September 30,March 31, 2016 and 2015 Generation, ComEd, PECO and BGE received $55by Registrant were as follows:

   Three Months Ended
March 31,
 
       2016          2015     

Generation

  $44   $  

ComEd

   39(a)   14(a) 

BGE

   21(a)     

Pepco

       112(b) 

(a)

Contribution paid by Exelon.

(b)

Contribution paid by PHI.

Pursuant to the orders approving the merger, Exelon expects to make equity contributions of $73 million, $75 million, $16$46 million and $6$49 million from Parent (Exelon), respectively. Duringto Pepco, DPL and ACE, respectively, in the nine months ended September 30, 2014, Generation, ComEdsecond quarter of 2016 to fund the after-tax amount of the customer bill credit and PECO received $55 million, $168 million and $24 million from Parent (Exelon), respectively.the customer base rate credit.

Other

For the ninethree months ended September 30, 2015,March 31, 2016, other financing activities primarily consistsconsist of debt issuance costs. See Note 1110 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information.further details of the Registrants’ debt issuances and retirements.

Credit Matters

The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $8.5$9.9 billion in aggregate total commitments of which $6.8$8.3 billion was available as of September 30, 2015,March 31, 2016, and of which no financial institution has more than 8%7% of the aggregate commitments. Exelon, Generation, ComEd, PECO and BGEcommitments for the Registrants. The Registrants had access to the commercial paper market during the thirdfirst quarter of 20152016 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PartPART I. ItemITEM 1A. Risk FactorsRISK FACTORS of Exelon’s 2014the Exelon 2015 Form 10-K for further information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation ComEd, PECO or BGE lost its investment grade credit rating as of September 30, 2015,March 31, 2016, it would have been required to provide incremental collateral as follows:of $1.9 billion to meet collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.2 billion.

The following table presents collateral held by each utility registrant at March 31, 2016 under PJM’s credit policy, incremental collateral required in the event each utility registrant lost its investment grade credit rating at March 31, 2016 and available credit facility capacity prior to any incremental collateral at March 31, 2016:

 

   Incremental
Collateral Required
(in millions)
   Available Credit Facility
Capacity Prior to Any
Incremental Collateral
(in millions)
 

Generation(a)

  $2,100    $4,841  

ComEd

   17     394  

PECO(b)

   18     599  

BGE(c)

   34     550  

(a)

Collateral obligations for derivatives, nonderivatives, normal purchase normal sales contracts and applicable payables and receivables, net of contractual right of offset under master netting agreements.

(b)

Related to PECO’s natural gas procurement contracts. No collateral would be required pursuant to PJM’s credit policy.

(c)

$6 million pursuant to PJM’s credit policy and collateral of $28 million related to BGE’s natural gas procurement contracts.

   PJM Credit
Policy
Collateral
   Incremental
Collateral
Required
   Available Credit Facility
Capacity Prior to Any
Incremental Collateral
 

ComEd

  $24    $17    $998  

PECO

   2     22     599  

BGE

   4     28     600  

Pepco

   2          250  

DPL

   3     9     250  

ACE

             250  

Exelon Credit Facilities

Exelon, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI meets its short-term liquidity requirements primarily through the issuance of commercial paper, short-term notes and the Exelon intercompany money pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 11 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further information regarding the Registrants’ credit facilities.

The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at September 30, 2015:March 31, 2016:

Commercial Paper Programs

 

Commercial Paper Issuer

  Maximum Program Size   Outstanding
Commercial Paper at
September 30, 2015
   Average Interest Rate on
Commercial Paper
Borrowings for the

nine months ended
September 30, 2015
   Maximum Program  Size(a)(b)(c)   Outstanding
Commercial Paper at
March 31, 2016
   Average Interest Rate on Commercial
Paper Borrowings for  the Three Months
Ended March 31, 2016
 

Exelon Corporate

  $500    $       $500    $     0.70

Generation

   5,600          0.49   5,300     1,378     0.99

ComEd

   1,000     604     0.52   1,000     643     0.79

PECO

   600             600          

BGE

   600     50     0.45   600     150     0.79

PHI Corporate

   875     442     1.07

Pepco

   500          0.68

DPL

   500     75     0.69

ACE

   350          0.65

(a)

Excludes $425 million bilateral credit facilities that do not back Generation’s commercial paper program.

(b)

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 14, 2016. These facilities are solely utilized to issue letters of credit. As of March 31, 2016, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $14 million, $21 million and $2 million, respectively.

(c)

Subject to available borrowing capacity under the credit facility.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit agreement,facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit agreement.facility. At March 31, 2016, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:

Credit Agreements

 

Borrower

  Facility Type  Aggregate  Bank
Commitment(a)
   Facility
Draws
   Outstanding
Letters of
Credit(b)
   Available Capacity at
September 30, 2015
   Facility Type  Aggregate Bank
Commitment(a)(b)
   Facility
Draws
   Outstanding
Letters of
Credit
   Available Capacity at
March 31, 2016
 
  Actual   To Support
Additional
Commercial
Paper(c)
    Actual   To Support
Additional
Commercial
Paper(c)
 

Exelon Corporate

  Syndicated Revolver  $500    $    $26    $474    $474    Syndicated Revolver  $500    $    $26    $474    $474  

Generation(d)

  Syndicated Revolver   5,300          599     4,701     4,701    Syndicated Revolver   5,300          1,164     4,136     2,758  

Generation

  Bilaterals   500          360     140     54    Bilaterals   425     80     329     16       

ComEd

  Syndicated Revolver   1,000          2     998     394    Syndicated Revolver   1,000          2     998     355  

PECO

  Syndicated Revolver   600          1     599     599    Syndicated Revolver   600          1     599     599  

BGE

  Syndicated Revolver   600               600     550    Syndicated Revolver   600               600     450  

PHI Corporate

  Syndicated Revolver   750          1     749     307  

Pepco

  Syndicated Revolver   250               250     250  

DPL

  Syndicated Revolver   250               250     175  

ACE

  Syndicated Revolver   250               250     250  

 

(a)

Excludes $123 million of credit facility agreements arranged withat minority and community banks at Generation, ComEd, PECO and BGE. These facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. See Note 11 — DebtAs of March 31, 2016, letters of credit issued under these agreements for Generation, ComEd, PECO and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further information.BGE totaled $7 million, $14 million, $21 million and $2 million, respectively.

(b)

Excludes nonrecourse debt letters of credit, see Note 1314 — Debt and Credit Agreements in the Exelon 20142015 Form 10-K for further information on Continental Wind nonrecourse debt.

(c)

Excludes $200$425 million bilateral credit facilities that do not back Generation’s commercial paper program.

(d)

Excludes ExGen Texas Power Financing’s $15.5$18 million of borrowed debt on its revolving credit facility.

As of September 30, 2015,March 31, 2016, there were nowas $80 million of borrowings under the Registrants’Generation’s bilateral credit facilities.

On October 23, 2015, a $100 million bilateral CENG credit facility was amended and extended for an additional two years. This facility has been utilized by CENG to fund working capital and capital projects. This facility does not back Generation’s commercial paper program.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s and BGE’s revolving credit facilitiesagreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon eachthe particular Registrant’s credit rating. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 7.5,

0.0 and 0.0 basis points respectively, for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 basis points respectively, for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement.commitments. The fee varies depending upon the respective credit ratings of the borrower.

Borrowings under PHI Corporate’s, Pepco’s, DPL’s, and ACE’s revolving credit agreements bear interest at a rate based upon either the greater of the prevailing prime rate, the federal funds effective rate plus 50 basis points or the one month LIBOR plus 100.0 basis points, or the prevailing Eurodollar rate, plus a margin based upon the particular Registrant’s credit rating. PHI Corporate, Pepco, DPL and ACE have margins of 22.5, 17.5, 17.5, and 17.5 basis points.

Each revolving credit agreement for Exelon, Generation, ComEd, PECO, and BGE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the ninethree months ended September 30, 2015:March 31, 2016:

 

   Exelon   Generation   ComEd   PECO   BGE 

Credit agreement threshold

   2.50 to 1     3.00 to 1     2.00 to 1     2.00 to 1     2.00 to 1  

At September 30, 2015,March 31, 2016, the interest coverage ratios at the RegistrantsExelon, Generation, ComEd, PECO and BGE were as follows:

 

   Exelon   Generation   ComEd   PECO   BGE 

Interest coverage ratio

   8.99     12.42     7.40     9.49     10.34  
   Exelon   Generation   ComEd   PECO   BGE 

Interest coverage ratio

   10.73     12.47     7.13     8.60     10.43  

An event of default under any Registrant’sExelon, Generation, ComEd, PECO or BGE’s indebtedness will not constitute an event of default under any of the other Registrants’others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility.

The revolving credit agreement for PHI, Pepco, DPL and ACE requires that each borrowing company maintain a maximum total indebtedness to total capitalization ratio. The following table summarizes the maximum thresholds reflected in the credit agreements for the three months ended March 31, 2016:

PHIPepcoDPLACE

Credit agreement threshold

0.65 to 10.65 to 10.65 to 10.65 to 1

At March 31, 2016, the total indebtedness to total capitalization ratios at PHI, Pepco, DPL and ACE were as follows:

   PHI   Pepco   DPL   ACE 

Total indebtedness to total capitalization ratio

   0.51     0.52     0.53     0.52  

PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. The termination date of this credit facility is currently August 1, 2018. In order for PHI, Pepco, DPL or ACE to use its facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. PHI, Pepco, DPL and ACE were in compliance with all covenants under their facilities at March 31, 2016.

The absence of a material adverse change in Exelon’s or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See “Credit Matters” above and Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon operates anand PHI operate intercompany money pool.pools. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2015,March 31, 2016, are presented in the following table:

 

  Three Months Ended
September 30, 2015
   As of
September 30, 2015
 

Participant

  Maximum
Contributed
   Maximum
Borrowed
   Contributed
(Borrowed)
 
Exelon Intercompany Money Pool  During the Three Months Ended
March 31, 2016
   As of March 31,
2016
 

Contributed (borrowed)

  Maximum
Contributed
   Maximum
Borrowed
   Contributed
(Borrowed)
 

Exelon Corporate

  $1,534     n/a    $165  

Generation

  $    $1,310    $(1,205        1,292     (63

PECO

        81     (55   285          160  

BSC

        356     (295        387     (325

Exelon Corporate

   1,579     N/A     1,555  

PHI Corporate(a)

   n/a            

PCI(a)

   63          63  

(a)

As a result of the merger, PHI Corporate and PCI began to participate in the Exelon Intercompany Money Pool effective March 24, 2016.

PHI Intercompany Money Pool  During the Three Months Ended
March 31, 2016
   As of March 31,
2016
 

Contributed (borrowed)

  Maximum
Contributed
   Maximum
Borrowed
   Contributed
(Borrowed)
 

PHI Corporate

  $129     n/a    $129  

Pepco

               

DPL

               

ACE

               

PHISCO

        151     (129

Investments in Nuclear Decommissioning Trust Funds

Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s and CENG’s NDT fund investment policy. Generation’s and CENG’s investment policies which outline investment guidelines forestablish limits on the trusts.concentration of holdings in any one company and also in any one industry. See Note 1312 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.

Shelf Registration Statements

The RegistrantsExelon, Generation, ComEd, PECO and BGE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in May 2017. PHI, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2016. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations

As of September 30, 2015,Generation, ComEd, had $442 million available in long-term debt refinancing authorityPECO, BGE, Pepco, DPL and $803 million available in new money long-term debt financing authority from the ICC. As of September 30, 2015, PECO had $1.1 billion available in long-term debt financing authority from the PAPUC. As of September 30, 2015, BGE had $1.4 billion available inAce are required to obtain short-term and long-term financing authority from MDPSC.Federal and State Commissions as follows:

As of September 30, 2015, ComEd, PECO and BGE had short-term

   Short-term Financing Authority(a)   Long-term Financing Authority 
  Commission   Expiration Date  Amount
(in millions)
   Commission  Amount
(in millions)
 

ComEd(b)

   FERC    December 31, 2017  $2,500    ICC  $1,795  

PECO

   FERC    December 31, 2017   1,500    PAPUC   1,900  

BGE

   FERC    December 31, 2017   700    MDPSC   1,400  

Pepco

   FERC    June 30, 2016   500    MDPSC / DCPSC   550  

DPL

   FERC    June 30, 2016   500    MDPSC / DPSC   300  

ACE

   NJPU    January 1, 2018   350    NJBPU   300  

(a)

Generation currently has blanket financing authority it received from FERC which expires on December 31, 2015, of $2.5 billion, $2.5 billion, and $700 million, respectively. Generation currently has blanket financing authority from FERC, which was granted in connection with its market-based rate authority.

(b)

ComEd had $442 million available in long-term debt refinancing authority and $1,353 million available in new money long term debt financing authority from the ICC as of March 31, 2016.

Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 1923 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2015 Form 10-K and Note 16 — Commitments and Contingencies of the PHI 2015 Form 10-K for discussion of the Registrants’ commitments.

Generation, ComEd, PECO, BGE, Pepco, DPL and BGEACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd, PECO, and BGE have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Basis of PresentationSignificant Accounting Policies of the Combined Notes to Consolidated Financial Statements for further information.

For an in-depth discussion of the Registrant’sRegistrants’ contractual obligations and off-balance sheet arrangements, see Item 7. Management’s“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet ArrangementsArrangements” in the Exelon 20142015 Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Commercial Commitments” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Guarantees, Indemnifications and Off-Balance Sheet Arrangements” in the PHI 2015 Form 10-K.

Item 3.Quantitative and Qualitative Disclosures about Market Risk

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of the Registrants’ 20142015 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.

Generation

Normal Operations and Hedging Activities.    Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of ComEd’s, PECO’s and BGE’sthe Utility Registrants’ retail load, is sold into the wholesale markets. To reduce price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 20152016 through 2017.2018.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions thatwhich have not been hedged. Exelon’s hedging program involves the hedging of commodity risk for Exelon’s expected generation, typically on a ratable basis over a three-year period. As of September 30, 2015,March 31, 2016, the proportion of expected generation hedged is 97%-100%96%-99%, 81%-84%69%-72% and 51%-54%37%-40% for 2015, 2016, 2017 and 2017,2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to ComEd, PECO and BGEthe Utility Registrants to serve their retail load. See Note 4 — Mergers, Acquisitions, and Dispositions of the combined Notes to Consolidated Financial Statement for more detail regarding divestitures.

A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire non-proprietary trading portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on September 30, 2015March 31, 2016 market conditions and hedged position would be a $10 million increase in pre-tax net income for 2015 and a decrease in pre-tax net income of approximately $140$5 million, $315 million and $500$630 million, respectively, for 2016, 2017 and 2017.2018. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.

Proprietary Trading Activities.    Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 1,9131,220 GWhs and 5,3781,808 GWhs for the three and nine months ended September 30,March 31, 2016 and 2015, respectively, and 3,006 GWhs and 8,129 GWhs for the three and nine months ended September 30, 2014, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the ninethree months ended September 30, 2015March 31, 2016 resulted in pre-tax gains of $3 million due to net mark-to-market lossesgains of $5$3 million and immaterial realized gains of $8 million.gains. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and a one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $0.2$0.3 million of exposure during the quarter. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total RevenuesRevenue net of purchasedpurchase power and fuel expense from continuing operations for the ninethree months ended September 30, 2015March 31, 2016 of $7,041$2,297 million.

Fuel Procurement.    Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel isassemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 50% of Generation’s uranium concentrate requirements from 20152016 through 20192020 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial position.positions. See Note 19ITEM 7.Commitments and Contingencies of the Combined Notes to Consolidated Financial StatementsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding uranium and coal supply agreement matters.

ComEd

ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information regarding energy procurement and derivatives.

PECO

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements. PECO has certain full requirements

contracts and block contracts which are considered derivatives and qualify for the normal purchases and normal sales scope

exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Under the DSP Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.

PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

BGE

BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result, are accounted for on an accrual basis of accounting. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the residential shareholder return component of the administrative charge.

BGE has also entered into derivative natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.

BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

Pepco

Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

DPL

DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the DPSC. The SOS rates charged recover DPL’s wholesale power supply costs and include a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. DPL’s price risk related to electric supply procurement is limited. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

DPL provides natural gas to its customers under a GCR mechanism approved by the DPSC. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.

DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.

ACE

ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE’s wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

Trading and Non-Trading Marketing Activities.    The following detailed presentation of Exelon’s, Generation’s, ComEd’s, PHI’s and ComEd’sDPL’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s, PHI’s and ComEd’sDPL’s commodity mark-to-market net asset or liability balance sheet position from December 31, 20142015 to September 30, 2015.March 31, 2016. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings as well as the settlements from OCI to earnings and changes in fair value for the cash flow hedging activities that are recorded in accumulated OCI on the Consolidated Balance Sheets.earnings. This table excludes all normal purchase and normal sales contracts and does not segregate proprietary trading activity. See Note 109 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2015March 31, 2016 and December 31, 2014.2015.

 

   Generation  ComEd  Exelon 

Total mark-to-market energy contract net assets (liabilities) at December 31, 2014(a)

  $1,712   $(207 $1,505  

Total change in fair value during 2015 of contracts recorded in results of operations

   355        355  

Reclassification to realized at settlement of contracts recorded in results of operations

   (106      (106

Reclassification to realized at settlement from accumulated OCI

   (2      (2

Changes in fair value — energy derivatives(b)

       (36  (36

Changes in allocated collateral

   (373      (373

Changes in net option premium paid/(received)

   (27      (27

Option premium amortization

   (18      (18

Other balance sheet reclassifications(c)

   15        15  
  

 

 

  

 

 

  

 

 

 

Total mark-to-market energy contract net assets (liabilities) at September 30, 2015(a)

  $1,556   $(243 $1,313  
  

 

 

  

 

 

  

 

 

 
   Generation  ComEd  DPL(a)  Exelon(b) 

Total mark-to-market energy contract net assets (liabilities) at December 31, 2015(c)

  $1,753   $(247 $   $1,506  

Total change in fair value during 2016 of contracts recorded in results of operations

   159            159  

Reclassification to realized at settlement of contracts recorded in results of operations

   (47          (47

Changes in fair value — energy derivatives(d)

       (18  (1  (19

Changes in allocated collateral

   (195      1    (194

Changes in net option premium paid/(received)

   (17          (17

Option premium amortization

   9            9  

Other balance sheet reclassifications(e)

   (22          (22
  

 

 

  

 

 

  

 

 

  

 

 

 

Total mark-to-market energy contract net assets (liabilities) at March 31, 2016(c)

  $1,640   $(265 $   $1,375  
  

 

 

  

 

 

  

 

 

  

 

 

 

 

(a)

As of March 31, 2016 and December 31, 2015, PHI’s and DPL’s mark-to-market derivative liability was fully collateralized resulting in a zero balance. For the predecessor period of January 1, 2016 to March 23, 2016, PHI recorded a $1 million increase in fair value and $1 million increase in allocated collateral related to the exchange-traded futures.

(b)

As a result of the merger, Exelon amounts include PHI and DPL activity from March 24, 2016 to March 31, 2016. For the successor period of March 24, 2016 to March 31, 2016, there was no change in fair value and allocated collateral related to the exchange-traded futures.

(c)

Amounts are shown net of cash collateral paid to and received from counterparties.

(b)(d)

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of September 30, 2015,March 31, 2016, ComEd recorded a $243$265 million regulatory asset related to its mark-to-market derivative liabilities with unaffiliated suppliers. As of September 30, 2015,For the three months ended March 31, 2016, ComEd also recorded $44$25 million of decreases in fair value and $8 million of realized losses due to settlements of $7 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers. As of March 31, 2016, DPL recorded a $1 million regulatory asset related to its mark-to-market derivative liabilities.

(c)(e)

Other balance sheet reclassifications include derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums.

Fair Values.    The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 98 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

Exelon

 

 Maturities Within     Maturities Within Total  Fair
Value
 
 2015 2016 2017 2018 2019 2020  and
Beyond
 Total  Fair
Value
   2016 2017   2018 2019 2020 2021 and
Beyond
 

Normal operations, commodity derivative contracts(a)(b)

       

Normal Operations, Commodity derivative contracts(a)(b):

         

Actively quoted prices (Level 1)

 $(48 $(43 $7   $(23 $(21 $(8 $(136  $(76 $15    $(22 $(20 $(6 $   $(109

Prices provided by external sources (Level 2)

  203    298    26    7    (10  (6  518     529    191     (9  (10  1        702  

Prices based on model or other valuation methods (Level 3)(c)

  120    539    327    52    (27  (80  931     424    337     154    (21  (21  (91  782  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

  

 

  

 

 

Total

 $275   $794   $360   $36   $(58 $(94 $1,313    $877   $543    $123   $(51 $(26 $(91 $1,375  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

  

 

  

 

 

 

(a)

Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.

(b)

Amounts are shown net of cash collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $1,033$1,039 million at September 30, 2015.March 31, 2016.

(c)

Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Generation

 

 Maturities Within     Maturities Within   Total  Fair
Value
 
 2015 2016 2017 2018 2019 2020 and
Beyond
 Total  Fair
Value
   2016 2017   2018 2019 2020 2021 and
Beyond
   

Normal operations, commodity derivative contracts(a)(b)

       

Normal Operations, Commodity derivative contracts(a)(b):

          

Actively quoted prices (Level 1)

 $(48 $(43 $7   $(23 $(21 $(8 $(136  $(76 $15    $(22 $(20 $(6 $    $(109

Prices provided by external sources (Level 2)

  203    298    26    7    (10  (6  518     529    191     (9  (10  1         702  

Prices based on model or other valuation methods (Level 3)

  128    560    348    74    (6  70    1,174     444    361     177    2    2    61     1,047  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

  

 

   

 

 

Total

 $283   $815   $381   $58   $(37 $56   $1,556    $897   $567    $146   $(28 $(3 $61    $1,640  
 

 

  

 

  

 

  

 

  

 

  

 

  

 

   

 

  

 

   

 

  

 

  

 

  

 

   

 

 

 

(a)

Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.

(b)

Amounts are shown net of cash collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $1,033$1,039 million at September 30, 2015.March 31, 2016.

ComEd

 

   Maturities Within  Total  Fair
Value
 
   2015  2016  2017  2018  2019  2020 and
Beyond
  

Prices based on model or other valuation

methods(a)(Level 3)

  $(8 $(21 $(21 $(22 $(21 $(150 $(243
   Maturities Within  Total  Fair
Value
 
   2016  2017  2018  2019  2020  2021 and
Beyond
  

Prices based on model or other valuation methods (Level 3)(a)

  $(20 $(24 $(23 $(23 $(23 $(152 $(265

 

(a)

Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Credit Risk, Collateral and Contingent Related Features (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral and contingent related features.

Generation

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2015.March 31, 2016. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and BGEACE of $24$19 million, $33$37 million,$35 million, $36 million, $11 million, and $27$8 million as of March 31, 2016, respectively. See Note 2526 — Related Party Transactions of the Exelon 20142015 Form 10-K for additional information.

 

Rating as of September 30, 2015

  Total  Exposure
Before
Credit Collateral
   Credit
Collateral(a)
   Net
Exposure
   Number of
Counterparties
Greater than  10%
of Net Exposure
   Net Exposure  of
Counterparties
Greater than
10% of Net
Exposure
 

Rating as of March 31, 2016

  Total  Exposure
Before

Credit Collateral
   Credit
Collateral(a)
   Net
Exposure
   Number of
Counterparties
Greater than  10%
of Net Exposure
   Net Exposure  of
Counterparties
Greater than
10% of Net
Exposure
 

Investment grade

  $1,463    $18    $1,445     1    $444    $1,276    $58    $1,218     1    $436  

Non-investment grade

   55     15     40               71     32     39            

No external ratings

                  

Internally rated — investment grade

   535          535               516     1     515            

Internally rated — non-investment grade

   53     5     48               101     4     97            
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

��

Total

  $2,106    $38    $2,068     1    $444    $1,964    $95    $1,869     1    $436  
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

 

  Maturity of Credit Risk Exposure   Maturity of Credit Risk Exposure 

Rating as of September 30, 2015

  Less than
2 Years
   2-5 Years   Exposure
Greater  than
5 Years
   Total Exposure
Before Credit
Collateral
 

Rating as of March 31, 2016

  Less than
2 Years
   2-5 Years   Exposure
Greater  than
5 Years
   Total Exposure
Before Credit
Collateral
 

Investment grade

  $1,028    $414    $21    $1,463    $910    $347    $19    $1,276  

Non-investment grade

   38     13     4     55     59     12          71  

No external ratings

                

Internally rated — investment grade

   436     71     28     535     433     54     29     516  

Internally rated — non-investment grade

   50     3          53     83     18          101  
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Total

  $1,552    $501    $53    $2,106    $1,485    $431    $48    $1,964  
  

 

   

 

   

 

   

 

   

 

   

 

   

 

   

 

 

Net Credit Exposure by Type of Counterparty

  As of September  30,
2015
   As of March 31,
2016
 

Financial institutions

  $260    $116  

Investor-owned utilities, marketers, power producers

   867     781  

Energy cooperatives and municipalities

   908     909  

Other

   33     63  
  

 

   

 

 

Total

  $2,068    $1,869  
  

 

   

 

 

 

(a)

As of September 30, 2015,March 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $13$8 million of cash and $25$87 million of letters of credit.

ComEd, PECO and BGE

There have been no significant changes or additions to ComEd’s, PECO’s, or BGE’s exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 20142015 Annual Report on Form 10-K.

See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

PECOPHI, Pepco, DPL and ACE

There have been no significant changes or additions to PECO’sPHI’s, Pepco’s, DPL’s or ACE’s exposures to credit risk as described in ITEM 1A. RISK FACTORS of Exelon’s 2014PHI’s 2015 Annual Report on Form 10-K.

See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

BGE

There have been no significant changes or additions to BGE’s exposures to credit risk as described in ITEM 1A. RISK FACTORS of Exelon’s 2014 Annual Report on Form 10-K.

See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.

Collateral (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, fossil fuelnatural gas and other commodities. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.

Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. In order to post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 11Liquidity and Capital ResourcesDebt and Credit Agreements of the Combined Notes to Consolidated Financial StatementsMatters — Exelon Credit Facilities for additional information.

As of September 30, 2015,March 31, 2016, Generation had cash collateral of $1,065$1,063 million posted and cash collateral held of $21$16 million for external counterparties with derivative positions, of which $1,033$1,039 million and $7 million in net cash collateral posteddeposits were offset against commodity mark-to-marketenergy derivative and interest rate and foreign exchange derivative assets and liabilities related to underlying commodityenergy contracts, respectively. As of September 30, 2015, $4March 31, 2016, $1 million of cash collateral posted was not offset against net derivative positions because it was not associated with commodity-relatedenergy-related derivatives were associated with accrual positions, or as of the balance sheet date there were no positions to offset. See Note 1918 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

ComEd

As of September 30, 2015,March 31, 2016, ComEd held no collateral from suppliers in association with energy procurement contracts and held approximately $19 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 20142015 Exelon Form10-K for additional information.

PECO

As of September 30, 2015,March 31, 2016, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

BGE

BGE is not required to post collateral under its electric supply contracts. As of September 30, 2015,March 31, 2016, BGE was not required to post collateral under its natural gas procurement contracts nor was it holding collateral under its electric supply and natural gas procurement contracts. See Note 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Pepco

Pepco is not required to post collateral under its energy procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

DPL

DPL is not required to post collateral under its energy procurement contracts. As of March 31, 2016, DPL was required to post collateral of $1 million under its natural gas procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

ACE

ACE is not required to post collateral under its energy procurement contracts. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

RTOs and ISOs (Exelon, Generation, ComEd, PECO and BGE)(All Registrants)

Generation, ComEd, PECO, BGE, Pepco, DPL and BGEACE participate in all, or some, of the established, real-time energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no spot market, electricity

is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.

Exchange Traded Transactions (Exelon, Generation, PHI and Generation)DPL)

Generation enters into commodity transactions on NYMEX, ICE and the Nodal exchange. DPL enters into commodity transactions on ICE. The NYMEX, ICE and Nodal exchange clearinghouses act as the counterparty to each trade. Transactions on the NYMEX, ICE and Nodal exchange must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and Nodal exchange are significantly collateralized and have limited counterparty credit risk.

Long-Term Leases (Exelon)

Exelon’s Consolidated Balance Sheet, asOn March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of September 30, 2015, included a $348the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in coal-fired plantsthe MEAG Headleases and the Leases. The transaction resulted in Georgia subject to long-term leases. This investment represents the estimated residual valuea pre-tax gain of leased assets at the end$4 million which is reflected in Operating and maintenance expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income. See Note 6 — Impairment of Long-Lived Assets of the respective lease terms of $639 million, less unearned income of $291 million. As of December 31, 2014, Exelon’sCombined Notes to Consolidated Balance sheet included a $361 million net investment in coal-fired plants in Georgia subject to long-term leases, which represented the estimated residual value of leased assets at the end of the respective lease terms of $685 million, less unearned income of $324 million. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessee does not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the power itself or require the lessee to arrangeFinancial Statements for a third party to bid on a service contract for a period following the lease term. Exelon will be subject to residual value risk if the lessee does not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such

payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. Lessee performance under the lease agreements is supported by collateral and credit enhancement measures. Management regularly evaluates the creditworthiness of Exelon’s counterparties to these long-term leases. Exelon monitors the continuing credit quality of the credit enhancement party.additional information.

Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and BGE)PHI)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The RegistrantsExelon registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2015,March 31, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $752$1,287 million and $687 million of notional amounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $3$1 million decrease in Exelon Consolidated pre-tax income for the ninethree months ended September 30, 2015.March 31, 2016. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges.

Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As of September 30, 2015,March 31, 2016, Generation’s decommissioning trust funds are reflected at fair value on its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $434$470 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and

equity prices. See ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as a result of the current capital and credit market conditions.

Item 4.     Controls and Procedures

During the thirdfirst quarter of 2015,2016, each Registrant’sof Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of that Registrant’sits disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each Registrantall Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, is accumulated and made known to that Registrant’sExelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Consistent with guidance issued by the Securities and Exchange Commission that an assessment of internal controls over financial reporting of a recently acquired business may be omitted from management’s evaluation of disclosure controls and procedures, management is excluding an assessment of such internal controls of Integrys, which was acquired on November 1, 2014, from its evaluation of the effectiveness of Exelon’s and Generation’s disclosure controls and procedures. The total assets related to Integrys are approximately 0.58% and 1.19%, respectively, of Exelon’s and Generation’s related consolidated balance sheet amounts as of September 30, 2015. The total revenues related to Integrys are 6.65% and 10.32%, respectively, of Exelon’s and Generation’s related consolidated statements of operations and comprehensive income amounts for the three months ended September 30, 2015. The total revenues related to Integrys are 7.40% and 11.35%, respectively, of Exelon’s and Generation’s related consolidated statements of operations and comprehensive income amounts for the nine months ended September 30, 2015.

Accordingly, as of September 30, 2015,March 31, 2016, the principal executive officer and principal financial officer of each Registrantof Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve itstheir disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. On March 23, 2016, the merger between Exelon and PHI closed. There have been no changes in internal control over financial reporting that occurred during the thirdfirst quarter of 20152016, other than changes resulting from the PHI Merger, that have materially affected, or are reasonably likely to materially affect, any of the Registrant’sExelon’s, Generation’s, ComEd’s, PECO’s, BGE’s , PHI’s, Pepco’s, DPL’s and ACE’s internal control over financial reporting. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for further information regarding the PHI acquisition. Exelon’s management expects that the controls over financial reporting associated with PHI, Pepco, DPL and ACE from the date of the merger forward will be covered in the year-end assessment.

PART II — OTHER INFORMATION

 

Item 1Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 20142015 Form 10-K (b) ITEM 3. LEGAL PROCEEDINGS of PHI’s 2015 Form 10-K and (b) Note(c) Notes 5 — Regulatory Matters and Note 1918 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

 

Item 1ARisk Factors

Risks Related to Exelon

At September 30, 2015,Exclusive of the Registrant’s risk factors were consistentRisks Related to the Pending Merger with the risk factorsPHI described in Exelon’s 20142015 Form 10-K in ITEM 1A. RISK FACTORS, Exelon is, and will continue to be, subject to the risks described in Exelon’s and PHI’s 2015 Form 10-K in (a) ITEM 1A. RISK FACTORS, (b) ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and (c) ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA: Note 23 of the Combined Notes to Consolidated Financial Statements in Exelon’s 2015 Form 10-K and Note 16 of the Notes to Consolidated Financial Statements in PHI’s 2015 Form 10-K. As a result of the merger with PHI that closed on March 23, 2016 Exelon is subject to additional risks related to the merger as described below.

Risks Related to the PHI Merger

The merger may not achieve its anticipated results, and Exelon may be unable to integrate the operations of PHI in the manner expected.

Exelon and PHI entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the businesses of Exelon and PHI can be integrated in an efficient, effective and timely manner.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices and policies, any of which could adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs and could adversely affect Exelon’s future business, financial condition, operating results and prospects.

The merger may not be accretive to earnings and may cause dilution to Exelon’s earnings per share, which may negatively affect the market price of Exelon’s common stock.

The timing and amount of accretion expected could be significantly adversely affected by a number of uncertainties, including market conditions, risks related to Exelon’s businesses and whether the business of PHI is integrated in an efficient and effective manner. Exelon also could encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of Exelon’s common stock.

Exelon may incur unexpected transaction fees and merger-related costs in connection with the merger.

Exelon expects to incur a number of non-recurring expenses associated with completing the merger, as well as expenses related to combining the operations of the two companies. Exelon may incur additional unanticipated costs in the integration of the businesses of Exelon and PHI. Although Exelon expects that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.

Exelon may encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the PHI Merger.

As a result of the process to obtain regulatory approvals required for the PHI Merger, Exelon is committed to various programs, contributions and investments in several settlement agreements and regulatory approval orders. It is possible that Exelon may encounter delays, unexpected difficulties, or additional costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s financial position and operating results.

 

Item 4Mine Safety Disclosures

Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and BGEACE

Not applicable to the Registrants.

 

Item 6Exhibits

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrantregistrant and its subsidiaries on a consolidated basis and the relevant Registrantregistrant agrees to furnish a copy of any such instrument to the Commission upon request.

 

Exhibit

No.

  

Description

    2.1Letter Agreement, dated March 7, 2016, among Pepco Holdings, Inc., Exelon Corporation and Purple Acquisition Corp. (File No. 001-31403, Form 8-K dated March 7, 2016, Exhibit 2)
    3.1Exelon Corporation Amended and Restated Bylaws, as amended on April 26, 2016 (File No. 001-16169, Form 8-K dated April 29, 2016, Exhibit 4.1)
4.1  One Hundred and TwelfthThird Supplemental Indenture, dated as of September 15, 2015 from PECO to U.S.April 7, 2016, among Exelon Corporation and The Bank National Association,of New York Mellon Trust Company, N.A., as trustee (File no. 000-16844,No. 001-16169, Form 8-K dated October 5, 2015,April 7, 2016, Exhibit 4.1)4.2)
  10.1First Amendment to Loan Agreement, by and between Pepco Holdings LLC and The Bank of Nova Scotia, as administrative agent and lender, dated March 28, 2016 (File No. 001-31403, Form 8-K dated March 28, 2016, Exhibit 2)
  10.2Amendment To The Pepco Holdings, Inc. Second Revised And Restated Executive And Director Deferred Compensation Plan
  10.3First Amendment To The Pepco Holdings, Inc. 2014 Management Employee Severance Plan
  10.4First Amendment To The Pepco Holdings, Inc. Amended And Restated Change-In-Control/Severance Plan For Certain Executive Employees
  10.5Omnibus Amendment Pepco Holdings, Inc. Supplemental Executive Retirement Plans
  10.62016 Amendment to the Pepco Holdings, Inc. Retirement Plan

Exhibit

No.

Description

  18.1Letter from PricewaterhouseCoopers LLP to the Board of Directors of Pepco Holdings LLC dated May 10, 2016 regarding a change in accounting principles
  18.2Letter from PricewaterhouseCoopers LLP to the Board of Directors of Atlantic City Electric Company dated May 10, 2016 regarding a change in accounting principles
101.INS  XBRL Instance
101.SCH  XBRL Taxonomy Extension Schema
101.CAL  XBRL Taxonomy Extension Calculation
101.DEF  XBRL Taxonomy Extension Definition
101.LAB  XBRL Taxonomy Extension Labels
101.PRE  XBRL Taxonomy Extension Presentation

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2015March 31, 2016 filed by the following officers for the following companies:

 

31-1  — Filed by Christopher M. Crane for Exelon Corporation
31-2  — Filed by Jonathan W. Thayer for Exelon Corporation
31-3  — Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
31-4  — Filed by Bryan P. Wright for Exelon Generation Company, LLC
31-5  — Filed by Anne R. Pramaggiore for Commonwealth Edison Company
31-6  — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
31-7  — Filed by Craig L. Adams for PECO Energy Company
31-8  — Filed by Phillip S. Barnett for PECO Energy Company
31-9  — Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
31-10  — Filed by David M. Vahos for Baltimore Gas and Electric Company
31-11— Filed by David M. Velazquez for Pepco Holdings LLC
31-12— Filed by Donna J. Kinzel for Pepco Holdings LLC
31-13— Filed by David M. Velazquez for Potomac Electric Power Company
31-14— Filed by Donna J. Kinzel for Potomac Electric Power Company
31-15— Filed by David M. Velazquez for Delmarva Power & Light Company
31-16— Filed by Donna J. Kinzel for Delmarva Power & Light Company
31-17— Filed by David M. Velazquez for Atlantic City Electric Company
31-18— Filed by Donna J. Kinzel for Atlantic City Electric Company

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2015March 31, 2016 filed by the following officers for the following companies:

 

32-1  — Filed by Christopher M. Crane for Exelon Corporation
32-2  — Filed by Jonathan W. Thayer for Exelon Corporation
32-3  — Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
32-4  — Filed by Bryan P. Wright for Exelon Generation Company, LLC
32-5  — Filed by Anne R. Pramaggiore for Commonwealth Edison Company
32-6  — Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
32-7  — Filed by Craig L. Adams for PECO Energy Company
32-8  — Filed by Phillip S. Barnett for PECO Energy Company
32-9  — Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
32-10  — Filed by David M. Vahos for Baltimore Gas and Electric Company
32-11— Filed by David M. Velazquez for Pepco Holdings LLC
32-12— Filed by Donna J. Kinzel for Pepco Holdings LLC
32-13— Filed by David M. Velazquez for Potomac Electric Power Company
32-14— Filed by Donna J. Kinzel for Potomac Electric Power Company
32-15— Filed by David M. Velazquez for Delmarva Power & Light Company
32-16— Filed by Donna J. Kinzel for Delmarva Power & Light Company
32-17— Filed by David M. Velazquez for Atlantic City Electric Company
32-18— Filed by Donna J. Kinzel for Atlantic City Electric Company

SIGNATURES

Pursuant to requirements 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.

EXELON CORPORATION

 

/s/S/    CHRISTOPHER M. CRANE

  

/s/S/    JONATHAN W. THAYER

Christopher M. Crane  Jonathan W. Thayer

President and Chief Executive Officer

(Principal Executive Officer) and Director

  

Senior Executive Vice President and Chief Financial

Officer

(Principal Financial Officer)

/s/S/    DUANE M. DESPARTE

  
Duane M. DesParte  

Senior Vice President and Corporate Controller

(Principal Accounting Officer)

  

October 30, 2015May 10, 2016

Pursuant to requirements 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.

EXELON GENERATION COMPANY, LLC

 

/s/S/    KENNETH W. CORNEW

  

/s/S/    BRYAN P. WRIGHT

Kenneth W. Cornew  Bryan P. Wright

President and Chief Executive Officer

(Principal Executive Officer)

  

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

/s/    ROBERTS/    MATTHEW M. AN. BIKENAUER

  
Robert M. AikenMatthew N. Bauer  
Chief Accounting Officer

Vice President and Controller

(Principal Accounting Officer)

  

October 30, 2015May 10, 2016

Pursuant to requirements 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.

COMMONWEALTH EDISON COMPANY

 

/s/S/    ANNE R. PRAMAGGIORE

  

/s/S/    JOSEPH R. TRPIK, JR.

Anne R. Pramaggiore  Joseph R. Trpik, Jr.

President and Chief Executive Officer

(Principal Executive Officer)

  

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/s/S/    GERALD J. KOZEL

  
Gerald J. Kozel  

Vice President and Controller

(Principal Accounting Officer)

  

October 30, 2015May 10, 2016

Pursuant to requirements 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.

PECO ENERGY COMPANY

 

/s/S/    CRAIG L. ADAMS

  

/s/S/    PHILLIP S. BARNETT

Craig L. Adams  Phillip S. Barnett

President and Chief Executive Officer

(Principal Executive Officer)

  

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/s/S/    SCOTT A. BAILEY

  
Scott A. Bailey  

Vice President and Controller

(Principal Accounting Officer)

  

October 30, 2015May 10, 2016

Pursuant to requirements 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.

BALTIMORE GAS AND ELECTRIC COMPANY

 

/s/S/    CALVIN G. BUTLER, JR.

  

/s/S/    DAVID M. VAHOS

Calvin G. Butler, Jr.  David M. Vahos

Chief Executive Officer

(Principal Executive Officer)

  

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/s/    MATTHEWS/    ANDREW N. BW. HAUEROLMES

  
Matthew N. BauerAndrew W. Holmes  

Vice President and Controller

(Principal Accounting Officer)

  

October 30, 2015May 10, 2016

Pursuant to requirements 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.

PEPCO HOLDINGS LLC

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL

David M. VelazquezDonna J. Kinzel

President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/S/    ROBERT M. AIKEN

Robert M. Aiken

Vice President and Controller

(Principal Accounting Officer)

May 10, 2016

Pursuant to requirements 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.

POTOMAC ELECTRIC POWER COMPANY

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL

David M. VelazquezDonna J. Kinzel

President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/S/    ROBERT M. AIKEN

Robert M. Aiken

Vice President and Controller

(Principal Accounting Officer)

May 10, 2016

Pursuant to requirements 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.

DELMARVA POWER & LIGHT COMPANY

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL

David M. VelazquezDonna J. Kinzel

President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/S/    ROBERT M. AIKEN

Robert M. Aiken

Vice President and Controller

(Principal Accounting Officer)

May 10, 2016

Pursuant to requirements 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.

ATLANTIC CITY ELECTRIC COMPANY

/S/    DAVID M. VELAZQUEZ

/S/    DONNA J. KINZEL

David M. VelazquezDonna J. Kinzel

President and Chief Executive Officer

(Principal Executive Officer)

Senior Vice President, Chief Financial Officer and

Treasurer

(Principal Financial Officer)

/S/    ROBERT M. AIKEN

Robert M. Aiken

Vice President and Controller

(Principal Accounting Officer)

May 10, 2016

 

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