UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q
(Mark One)
 xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended JuneSeptember 30, 2014
or
 ¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12291
THE AES CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 54 1163725
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer Identification No.)
4300 Wilson Boulevard Arlington, Virginia 22203
(Address of principal executive offices) (Zip Code)
(703) 522-1315
Registrant’s telephone number, including area code:

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 the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x
 
Accelerated filer ¨
 
Non-accelerated filer ¨
 
Smaller reporting company ¨
       
    (Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨    No  x

The number of shares outstanding of Registrant’s Common Stock, par value $0.01 per share, on AugustNovember 3, 2014 was 723,269,141713,046,356
 




THE AES CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNESEPTEMBER 30, 2014
TABLE OF CONTENTS
 
PART I: FINANCIAL INFORMATION
1
   
ITEM 1.
FINANCIAL STATEMENTS
1
 
Condensed Consolidated Balance Sheets
1
 
Condensed Consolidated Statements of Operations
2
 
Condensed Consolidated Statements of Comprehensive Income
3
 
Condensed Consolidated Statements of Cash Flows
4
 
Notes to Condensed Consolidated Financial Statements
5
   
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
2527
   
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
5356
   
ITEM 4.
CONTROLS AND PROCEDURES
5658
  
PART II: OTHER INFORMATION
5760
   
ITEM 1.
LEGAL PROCEEDINGS
5760
   
ITEM 1A.
RISK FACTORS
6164
   
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
6164
   
ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
6265
   
ITEM 4.
MINE SAFETY DISCLOSURES
6265
   
ITEM 5.
OTHER INFORMATION
6265
   
ITEM 6.
EXHIBITS
6265
  
SIGNATURES
6366




PART I: FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS
THE AES CORPORATION
Condensed Consolidated Balance Sheets
(Unaudited)
 June 30,
2014		 December 31,
2013		 September 30,
2014		 December 31,
2013
 
(in millions, except share
and per share data)
 
(in millions, except share
and per share data)
ASSETS        
CURRENT ASSETS        
Cash and cash equivalents $1,515
 $1,642
 $1,670
 $1,642
Restricted cash 482
 597
 487
 597
Short-term investments 424
 668
 686
 668
Accounts receivable, net of allowance for doubtful accounts of $126 and $134, respectively 2,689
 2,363
Accounts receivable, net of allowance for doubtful accounts of $104 and $134, respectively 2,755
 2,363
Inventory 710
 684
 741
 684
Deferred income taxes 190
 166
 148
 166
Prepaid expenses 177
 179
 208
 179
Other current assets 1,220
 976
 1,192
 976
Current assets of discontinued operations and held-for-sale businesses —
 464
 —
 464
Total current assets 7,407
 7,739
 7,887
 7,739
NONCURRENT ASSETS        
Property, Plant and Equipment:        
Land 958
 922
 903
 922
Electric generation, distribution assets and other 31,321
 30,596
 30,670
 30,596
Accumulated depreciation (10,095) (9,604) (9,981) (9,604)
Construction in progress 3,444
 3,198
 3,475
 3,198
Property, plant and equipment, net 25,628
 25,112
 25,067
 25,112
Other Assets:        
Investments in and advances to affiliates 1,000
 1,010
 704
 1,010
Debt service reserves and other deposits 549
 541
 480
 541
Goodwill 1,468
 1,622
 1,468
 1,622
Other intangible assets, net of accumulated amortization of $156 and $153, respectively 299
 297
 283
 297
Deferred income taxes 656
 666
 693
 666
Other noncurrent assets 2,426
 2,170
 2,401
 2,170
Noncurrent assets of discontinued operations and held-for-sale businesses —
 1,254
 —
 1,254
Total other assets 6,398
 7,560
 6,029
 7,560
TOTAL ASSETS $39,433
 $40,411
 $38,983
 $40,411
LIABILITIES AND EQUITY        
CURRENT LIABILITIES        
Accounts payable $2,130
 $2,259
 $2,203
 $2,259
Accrued interest 272
 263
 402
 263
Accrued and other liabilities 2,170
 2,114
 2,121
 2,114
Non-recourse debt, including $255 and $267, respectively, related to variable interest entities 2,095
 2,062
Non-recourse debt, including $242 and $267, respectively, related to variable interest entities 2,347
 2,062
Recourse debt —
 118
 —
 118
Current liabilities of discontinued operations and held-for-sale businesses —
 837
 —
 837
Total current liabilities 6,667
 7,653
 7,073
 7,653
NONCURRENT LIABILITIES        
Non-recourse debt, including $1,026 and $979, respectively, related to variable interest entities 13,845
 13,318
Non-recourse debt, including $1,036 and $979, respectively, related to variable interest entities 13,372
 13,318
Recourse debt 5,783
 5,551
 5,347
 5,551
Deferred income taxes 1,114
 1,119
 1,165
 1,119
Pension and other post-retirement liabilities 1,332
 1,310
 1,224
 1,310
Other noncurrent liabilities 3,106
 3,299
 3,158
 3,299
Noncurrent liabilities of discontinued operations and held-for-sale businesses —
 432
 —
 432
Total noncurrent liabilities 25,180
 25,029
 24,266
 25,029
Contingencies and Commitments (see Note 9) 
 
 
 
Cumulative preferred stock of subsidiaries 78
 78
 78
 78
EQUITY        
THE AES CORPORATION STOCKHOLDERS’ EQUITY        
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 814,347,602 issued and 723,221,508 outstanding at June 30, 2014 and 813,316,510 issued and 722,508,342 outstanding at December 31, 2013) 8
 8
Common stock ($0.01 par value, 1,200,000,000 shares authorized; 814,456,569 issued and 715,960,427 outstanding at September 30, 2014 and 813,316,510 issued and 722,508,342 outstanding at December 31, 2013) 8
 8
Additional paid-in capital 8,396
 8,443
 8,355
 8,443
Accumulated deficit (75) (150)
Retained earnings (accumulated deficit) 413
 (150)
Accumulated other comprehensive loss (3,023) (2,882) (3,176) (2,882)
Treasury stock, at cost (91,126,094 shares at June 30, 2014 and 90,808,168 shares at December 31, 2013) (1,095) (1,089)
Treasury stock, at cost (98,496,142 shares at September 30, 2014 and 90,808,168 shares at December 31, 2013) (1,203) (1,089)
Total AES Corporation stockholders’ equity 4,211
 4,330
 4,397
 4,330
NONCONTROLLING INTERESTS 3,297
 3,321
 3,169
 3,321
Total equity 7,508
 7,651
 7,566
 7,651
TOTAL LIABILITIES AND EQUITY $39,433
 $40,411
 $38,983
 $40,411
See Notes to Condensed Consolidated Financial Statements.
1



THE AES CORPORATION
Condensed Consolidated Statements of Operations
(Unaudited)
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions, except per share amounts) (in millions, except per share amounts)
Revenue:                
Regulated $2,116
 $1,974
 $4,258
 $4,113
 $2,378
 $2,062
 $6,636
 $6,175
Non-Regulated 2,195
 1,971
 4,315
 3,982
 2,063
 1,934
 6,378
 5,916
Total revenue 4,311
 3,945
 8,573
 8,095
 4,441
 3,996
 13,014
 12,091
Cost of Sales:                
Regulated (1,844) (1,632) (3,776) (3,419) (1,956) (1,663) (5,732) (5,082)
Non-Regulated (1,648) (1,412) (3,184) (3,026) (1,718) (1,406) (4,902) (4,432)
Total cost of sales (3,492) (3,044) (6,960) (6,445) (3,674) (3,069) (10,634) (9,514)
Operating margin 819
 901
 1,613
 1,650
 767
 927
 2,380
 2,577
General and administrative expenses (52) (53) (103) (107) (45) (53) (148) (160)
Interest expense (323) (337) (696) (707) (390) (358) (1,086) (1,065)
Interest income 73
 63
 136
 128
 69
 85
 205
 213
Loss on extinguishment of debt (15) (165) (149) (212) (47) —
 (196) (212)
Other expense (17) (17) (25) (43) (12) (15) (37) (58)
Other income 33
 13
 44
 81
 12
 25
 56
 106
Gain on sale of investments —
 20
 1
 23
Gain on disposals and sale of investments 362
 3
 363
 26
Goodwill impairment expense —
 —
 (154) —
 —
 (58) (154) (58)
Asset impairment expense (63) —
 (75) (48) (15) (16) (90) (64)
Foreign currency transaction gains (losses) 7
 (18) (12) (48) (79) 32
 (91) (16)
Other non-operating expense (44) —
 (44) —
 (16) (122) (60) (122)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES AND EQUITY IN EARNINGS OF AFFILIATES 418
 407
 536
 717
 606
 450
 1,142
 1,167
Income tax expense (157) (76) (211) (159) (92) (126) (303) (285)
Net equity in earnings of affiliates 20
 2
 45
 6
 (6) 15
 39
 21
INCOME FROM CONTINUING OPERATIONS 281
 333
 370
 564
 508
 339
 878
 903
Income (loss) from operations of discontinued businesses, net of income tax expense of $8, $7, $22, and $5, respectively 7
 (3) 27
 1
Net (loss) gain from disposal and impairments of discontinued businesses, net of income tax (benefit) expense of $5, $0, $4, and $(1), respectively (13) 3
 (56) (33)
Income (loss) from operations of discontinued businesses, net of income tax expense (benefit) of $0, $(3), $22, and $2, respectively —
 (38) 27
 (37)
Net loss from disposal and impairments of discontinued businesses, net of income tax expense (benefit) of $0, $(1), $4, and $(2), respectively —
 (78) (56) (111)
NET INCOME 275
 333
 341
 532
 508
 223
 849
 755
Noncontrolling interests:                
Less: Income from continuing operations attributable to noncontrolling interests (139) (166) (275) (285) (20) (164) (295) (449)
Less: (Income) loss from discontinued operations attributable to noncontrolling interests (3) —
 9
 2
Less: Loss from discontinued operations attributable to noncontrolling interests —
 12
 9
 14
Total net income attributable to noncontrolling interests (142) (166) (266) (283) (20) (152) (286) (435)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION $133
 $167
 $75
 $249
 $488
 $71
 $563
 $320
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:                
Income from continuing operations, net of tax $142
 $167
 $95
 $279
 $488
 $175
 $583
 $454
Loss from discontinued operations, net of tax (9) —
 (20) (30) —
 (104) (20) (134)
Net income $133
 $167
 $75
 $249
 $488
 $71
 $563
 $320
BASIC EARNINGS PER SHARE:                
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax $0.20
 $0.22
 $0.13
 $0.37
 $0.68
 $0.23
 $0.81
 $0.61
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax (0.02) —
 (0.03) (0.04) —
 (0.14) (0.03) (0.18)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS $0.18
 $0.22
 $0.10
 $0.33
 $0.68
 $0.09
 $0.78
 $0.43
DILUTED EARNINGS PER SHARE:                
Income from continuing operations attributable to The AES Corporation common stockholders, net of tax $0.20
 $0.22
 $0.13
 $0.37
 $0.67
 $0.23
 $0.81
 $0.61
Loss from discontinued operations attributable to The AES Corporation common stockholders, net of tax (0.02) —
 (0.03) (0.04) —
 (0.14) (0.03) (0.18)
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS $0.18
 $0.22
 $0.10
 $0.33
 $0.67
 $0.09
 $0.78
 $0.43
DILUTED SHARES OUTSTANDING 728
 751
 728
 750
 740
 747
 727
 749
DIVIDENDS DECLARED PER COMMON SHARE $0.05
 $0.08
 $0.05
 $0.08
 $0.05
 $—
 $0.10
 $0.08
See Notes to Condensed Consolidated Financial Statements.

2



THE AES CORPORATION
Condensed Consolidated Statements of Comprehensive Income
(Unaudited)

 Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
NET INCOME $275
 $333
 $341
 $532
 $508
 $223
 $849
 $755
Available-for-sale securities activity:                
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $0, $0, $0 and $1, respectively —
 (1) —
 (1)
Change in fair value of available-for-sale securities, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively (1) —
 (1) (1)
Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively —
 1
 —
 1
 —
 —
 —
 1
Total change in fair value of available-for-sale securities —
 —
 —
 —
 (1) —
 (1) —
Foreign currency translation activity:                
Foreign currency translation adjustments, net of income tax (expense) benefit of $(7), $2, $(8) and $2, respectively 24
 (226) 29
 (258)
Foreign currency translation adjustments, net of income tax (expense) benefit of $1, $1, $(7) and $3, respectively (329) (6) (300) (264)
Reclassification to earnings, net of income tax (expense) benefit of $0, $0, $0 and $0, respectively (53) 44
 (47) 41
 (4) —
 (51) 41
Total foreign currency translation adjustments (29) (182) (18) (217) (333) (6) (351) (223)
Derivative activity:                
Change in derivative fair value, net of income tax (expense) benefit of $22, $(28), $46 and $(28), respectively (105) 102
 (225) 86
Reclassification to earnings, net of income tax (expense) of $(10), $(15), $(13) and $(22), respectively 13
 61
 32
 85
Change in derivative fair value, net of income tax (expense) benefit of $6, $0, $52 and $(28), respectively (36) 7
 (261) 93
Reclassification to earnings, net of income tax (expense) of $(10), $(8), $(23) and $(30), respectively 44
 27
 76
 112
Total change in fair value of derivatives (92) 163
 (193) 171
 8
 34
 (185) 205
Pension activity:                
Change in pension adjustments due to prior service cost, net of income tax (expense) benefit of $(1), $0, $(1), $0, respectively 1
 —
 1
 —
Change in pension adjustments due to disposal of discontinued operations for the period, net of income tax (expense) benefit of $(9), $0, $(9), $0, respectively 14
 —
 14
 —
Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $2, $(7), $(1) and $(14), respectively 10
 13
 16
 27
Change in pension adjustments due to prior service cost, net of income tax (expense) benefit of $0, $0, $(1) $0, respectively —
 —
 1
 —
Change in pension adjustments due to disposal of discontinued operations for the period, net of income tax (expense) benefit of $0, $0, $(9), $0, respectively —
 —
 14
 —
Reclassification to earnings due to amortization of net actuarial loss, net of income tax (expense) benefit of $(3), $(6), $(4) and $(20), respectively 5
 12
 21
 39
Total pension adjustments 25
 13
 31
 27
 5
 12
 36
 39
OTHER COMPREHENSIVE (LOSS) (96) (6) (180) (19)
OTHER COMPREHENSIVE INCOME (LOSS) (321) 40
 (501) 21
COMPREHENSIVE INCOME 179
 327
 161
 513
 187
 263
 348
 776
Less: Comprehensive (income) attributable to noncontrolling interests (102) (147) (227) (283)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE AES CORPORATION $77
 $180
 $(66) $230
Less: Comprehensive (income) loss attributable to noncontrolling interests 108
 (171) (119) (454)
COMPREHENSIVE INCOME ATTRIBUTABLE TO THE AES CORPORATION $295
 $92
 $229
 $322


See Notes to Condensed Consolidated Financial Statements.

3



THE AES CORPORATION
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 Six Months Ended June 30, Nine Months Ended September 30,
 2014 2013 2014 2013
 (in millions) (in millions)
OPERATING ACTIVITIES:        
Net income $341
 $532
 $849
 $755
Adjustments to net income:        
Depreciation and amortization 625
 661
 937
 982
Loss (gain) on sale of assets and investments 7
 (2)
(Gain) loss on sale of assets and investments (344) 4
Impairment expenses 273
 48
 304
 309
Deferred income taxes 52
 (46) 83
 (82)
Provisions for contingencies (48) 36
Provisions for (releases of) contingencies (41) 33
Loss on the extinguishment of debt 149
 212
 196
 212
Loss on disposals and impairments - discontinued operations 51
 31
 51
 108
Other 46
 23
 135
 (26)
Changes in operating assets and liabilities        
(Increase) decrease in accounts receivable (312) 191
 (494) 135
(Increase) decrease in inventory (39) (12) (75) (6)
(Increase) decrease in prepaid expenses and other current assets (72) 55
 (12) 403
(Increase) decrease in other assets (316) (147) (439) (149)
Increase (decrease) in accounts payable and other current liabilities (194) (252) (14) (578)
Increase (decrease) in income tax payables, net and other tax payables (176) (134) (239) (66)
Increase (decrease) in other liabilities 66
 (11) 319
 6
Net cash provided by operating activities 453
 1,185
 1,216
 2,040
INVESTING ACTIVITIES:        
Capital expenditures (908) (866) (1,389) (1,330)
Acquisitions - net of cash acquired (728) (3)
Acquisitions, net of cash acquired (728) (3)
Proceeds from the sale of businesses, net of cash sold 890
 135
 1,668
 167
Proceeds from the sale of assets 16
 43
 29
 52
Sale of short-term investments 2,198
 2,311
 3,335
 3,375
Purchase of short-term investments (1,925) (2,381) (3,386) (3,638)
Decrease in restricted cash, debt service reserves and other assets 127
 32
 162
 75
Other investing (61) 23
 (55) 35
Net cash used in investing activities (391) (706) (364) (1,267)
FINANCING ACTIVITIES:        
Borrowings under the revolving credit facilities, net 130
 33
Borrowings (repayments) under the revolving credit facilities, net 14
 (22)
Issuance of recourse debt 1,525
 750
 1,525
 750
Issuance of non-recourse debt 1,710
 2,383
 2,253
 3,082
Repayments of recourse debt (1,663) (1,206) (2,019) (1,208)
Repayments of non-recourse debt (1,349) (2,169) (1,639) (2,288)
Payments for financing fees (105) (127) (111) (148)
Distributions to noncontrolling interests (197) (211) (377) (385)
Contributions from noncontrolling interests 110
 76
 114
 157
Dividends paid on AES common stock (72) (60) (108) (89)
Payments for financed capital expenditures (312) (257) (360) (436)
Purchase of treasury stock (32) (18) (140) (63)
Other financing 5
 7
 4
 15
Net cash used in financing activities (250) (799) (844) (635)
Effect of exchange rate changes on cash (14) (39) (55) (37)
Decrease in cash of discontinued and held-for-sale businesses 75
 8
 75
 23
Total decrease in cash and cash equivalents (127) (351)
Total increase in cash and cash equivalents 28
 124
Cash and cash equivalents, beginning 1,642
 1,900
 1,642
 1,900
Cash and cash equivalents, ending $1,515
 $1,549
 $1,670
 $2,024
SUPPLEMENTAL DISCLOSURES:        
Cash payments for interest, net of amounts capitalized $676
 $700
 $902
 $923
Cash payments for income taxes, net of refunds $332
 $432
 $401
 $506
SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:        
Assets received upon sale of subsidiaries $44
 $—
 $44
 $—
Assets acquired through capital lease $13
 $10
 $13
 $12
Dividends declared but not yet paid $—
 $30
See Notes to Condensed Consolidated Financial Statements.

4



THE AES CORPORATION
Notes to Condensed Consolidated Financial Statements
For the Three and SixNine Months Ended JuneSeptember 30, 2014 and 2013
1. FINANCIAL STATEMENT PRESENTATION
Discontinued Operations and Reclassifications
Effective July 1, 2014, the Company prospectively adopted Accounting Standards Update ("ASU") No. 2014-08, which significantly changed the previous accounting guidance for discontinued operations as discussed further below. The prior-period condensed consolidated financial statements in this Quarterly Report on Form 10-Q (“Form 10-Q”) have been reclassified to reflect the businesses which met the criteria to be reported as held-for-sale and discontinued operations under the previous accounting guidance as discussed in Note 1718 — Discontinued Operations and Held-for-Sale Businesses.There were no disposals during the third quarter of 2014 which met the criteria to be reported as discontinued operations under ASU No. 2014-08. However, the disposal of the U.K. Wind business during the third quarter of 2014 would have met the criteria to be reported as a discontinued operation prior to the adoption of ASU 2014-08.
Consolidation
In this Quarterly Report the terms “AES,” “the Company,” “us” or “we” refer to the consolidated entity including its subsidiaries and affiliates. The terms “The AES Corporation,” “the Parent” or “the Parent Company” refer only to the publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates. Furthermore, variable interest entities (“VIEs”) in which the Company has a variable interest have been consolidated where the Company is the primary beneficiary. Investments in which the Company has the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting. All intercompany transactions and balances have been eliminated in consolidation.
Interim Financial Presentation
The accompanying unaudited condensed consolidated financial statements and footnotes have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”), as contained in the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification ("ASC"), for interim financial information and Article 10 of Regulation S-X issued by the U.S. Securities and Exchange Commission (“SEC”). Accordingly, they do not include all the information and footnotes required by U.S. GAAP for annual fiscal reporting periods. In the opinion of management, the interim financial information includes all adjustments of a normal recurring nature necessary for a fair presentation of the results of operations, financial position, comprehensive income and cash flows. The results of operations for the three and sixnine months ended JuneSeptember 30, 2014 are not necessarily indicative of results that may be expected for the year ending December 31, 2014. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the 2013 audited consolidated financial statements and notes thereto, which are included in the 2013 Form 10-K filed with the SEC on February 25, 2014 (the “2013 Form 10-K”).
New Accounting Pronouncements Adopted
ASU No. 2013-11, Income Taxes (Topic 740), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force).
Effective January 1, 2014, the Company prospectively adopted ASU No. 2013-11, which requires the netting of unrecognized tax benefits (“UTBs”) against a deferred tax asset for a loss or other carryforward that would apply in settlement of uncertain tax positions. Under ASU No. 2013-11, UTBs are netted against all available same-jurisdiction losses or other tax carryforwards that would be utilized, rather than only against carryforwards that are created by the UTBs. The impact to the Company’s Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2014 was a reduction of $66 million to “Other noncurrent liabilities” and an offsetting increase to “Deferred income taxes” under “Noncurrent liabilities.” There were no impacts on the results of operations and cash flows.
Accounting Pronouncements Issued But Not Yet Effective
The following accounting standards have been issued, but are not yet effective for, and have not been adopted by AES.
ASU No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity
In AprilEffective July 1, 2014, the FASB issuedCompany prospectively adopted ASU No. 2014-08, which significantly changes the existing accounting guidance on discontinued operations. Early adoption is permitted for disposals (or classifications as held-for-sale) that have not been reported in financial statements previously issued. Under ASU No. 2014-08, only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations. Amongst other changes: equity method investments that were previously scoped-out of the discontinued operations accounting guidance are now included in the scope; a business can meet the criteria to be classified as held for saleheld-for-sale upon acquisition and can be reported in discontinued operations; and components where an entity retains significant continuing involvement or where operations and cash flows will not be eliminated from

5



ongoing operations as a result of a disposal transaction can meet the definition of discontinued operations. Additionally, where summarized amounts are presented on the face of the financial statements, reconciliations of those amounts to major classes of line items are also required. ASU No. 2014-08 requires additional disclosures for individually material components that do not meet the definition of discontinued operations. The Company's adoption of ASU No. 2014-08 effective July 1, 2014 did not have any net impact on its financial position or results of operations other than changing the classification of the UK Wind disposal which occurred during the third quarter of 2014. Under the previous accounting guidance, the UK Wind disposal would have met the discontinued operations criteria and would have been reclassified accordingly. See Note 18 — Discontinued Operations and Held-for-Sale Businesses for further information.
Accounting Pronouncements Issued But Not Yet Effective
The following accounting standards have been issued but are not yet effective for nor have been adopted by AES.
ASU No. 2014-05, Service Concession Arrangements (Topic 853)
In January 2014, the FASB issued ASU No. 2014-5 which states that certain service concession arrangements with public-sector entity grantors are not in scope of ASC 840, Leases ("ASC 840"). Operating entities with these types of arrangements with public-sector entities should not account for these arrangements under ASC 840 and should not recognize the related infrastructure as property, plant and equipment. Entities should apply other GAAP to the arrangement. The standard is effective for annual reporting periods beginning after December 15, 2014 and interim periods therein.

5



ASU No. 2014-08 should be applied to components classified as held for sale after its effective date. Early adoption is permitted, but onlypermitted. The guidance will be applied on a modified retrospective basis to service concession arrangements in existence at the beginning of the fiscal year of adoption, which is expected to be 2015 for disposals (or classifications as held for sale)AES. The Company has preliminarily identified certain concession arrangements that have not been reported in financial statements previously issued. The Companywill likely be affected by this standard and is currently evaluating the impact of adopting ASU No. 2014-08the standard on its financial position and results of operations. The adoption is expected to reduce the number of disposals that meet the definition of a discontinued operations.
ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606)
In May 2014, the FASB issued ASU No. 2014-09 which brings to a conclusion its project to clarifyclarifies principles for recognizing revenue while resultingand will result in a common revenue standard for U.S. GAAP and International Financial Reporting Standards. The objective of the new standard is to provide a single and comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets.comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The standard requires an entity to 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 standard is effective for annual reporting periods beginning after December 15, 2016 and interim periods therein. Early adoption is not permitted. The standard permits the use of either a full retrospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of adopting the standard on its financial position and results of operations.
ASU No. 2014-12, Compensation — Stock Compensation (Topic 718)
In June 2014, the FASB issued ASU No. 2014-12 which is intended to resolve the diverse accounting treatment in practice with compensation awards. The objective of the new standard is to clarify the treatment of accounting for performance targets which affect award vesting. The standard is effective for annual reporting periods beginning after December 15, 2015 and interim periods therein. Early adoption is permitted. The standard permits the use of either a prospective or modified retrospective approach. The Company has not yet selected a transition method and is currently evaluating the impact of the standard on its financial position and results of operations, but does not expect to be materially impacted.
2. INVENTORY
The following table summarizes the Company’s inventory balances as of the periods indicated:
 June 30, 2014 December 31, 2013 September 30, 2014 December 31, 2013
 (in millions) (in millions)
Coal, fuel oil and other raw materials $346
 $334
 $375
 $334
Spare parts and supplies 364
 350
 366
 350
Total $710
 $684
 $741
 $684
3. FAIR VALUE
The fair value of current financial assets and liabilities, debt service reserves and other deposits approximate their reported carrying amounts. The estimated fair value of the Company’s assets and liabilities have been determined using available market information. By virtue of these amounts being estimates and based on hypothetical transactions to sell assets or transfer liabilities, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. There were no changes in fair valuation techniques during the period and the Company continues to follow the valuation techniques described in Note 4. — Fair Value in Item 8. — Financial Statements and Supplementary Data of its 2013 Form 10-K.

6



Recurring Measurements
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were measured at fair value on a recurring basis as of the periods indicated:
 June 30, 2014 December 31, 2013 September 30, 2014 December 31, 2013
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
 (in millions) (in millions)
Assets                                
AVAILABLE-FOR-SALE:(1)
                                
Debt securities:                                
Unsecured debentures $—
 $260
 $—
 $260
 $—
 $435
 $—
 $435
 $—
 $484
 $—
 $484
 $—
 $435
 $—
 $435
Certificates of deposit —
 72
 —
 72
 —
 151
 —
 151
 —
 119
 —
 119
 —
 151
 —
 151
Government debt securities —
 44
 —
 44
 —
 25
 —
 25
 —
 56
 —
 56
 —
 25
 —
 25
Subtotal —
 376
 —
 376
 —
 611
 —
 611
 —
 659
 —
 659
 —
 611
 —
 611
Equity securities:                                
Mutual funds —
 47
 —
 47
 —
 44
 —
 44
 —
 38
 —
 38
 —
 44
 —
 44
Subtotal —
 47
 —
 47
 —
 44
 —
 44
 —
 38
 —
 38
 —
 44
 —
 44
Total available-for-sale —
 423
 —
 423
 —
 655
 —
 655
 —
 697
 —
 697
 —
 655
 —
 655
TRADING:                                
Equity securities:                                
Mutual funds 15
 —
 —
 15
 13
 —
 —
 13
 15
 —
 —
 15
 13
 —
 —
 13
Total trading 15
 —
 —
 15
 13
 —
 —
 13
 15
 —
 —
 15
 13
 —
 —
 13
DERIVATIVES:                                
Interest rate derivatives —
 22
 —
 22
 —
 98
 —
 98
 —
 20
 —
 20
 —
 98
 —
 98
Cross currency derivatives —
 —
 —
 —
 —
 5
 —
 5
Cross-currency derivatives —
 —
 —
 —
 —
 5
 —
 5
Foreign currency derivatives —
 15
 111
 126
 —
 15
 98
 113
 —
 29
 102
 131
 —
 15
 98
 113
Commodity derivatives —
 47
 17
 64
 —
 18
 6
 24
 —
 28
 13
 41
 —
 18
 6
 24
Total derivatives —
 84
 128
 212
 —
 136
 104
 240
 —
 77
 115
 192
 —
 136
 104
 240
TOTAL ASSETS $15
 $507
 $128
 $650
 $13
 $791
 $104
 $908
 $15
 $774
 $115
 $904
 $13
 $791
 $104
 $908
Liabilities                                
DERIVATIVES:                                
Interest rate derivatives $—
 $226
 $183
 $409
 $—
 $221
 $101
 $322
 $—
 $199
 $180
 $379
 $—
 $221
 $101
 $322
Cross currency derivatives —
 11
 —
 11
 —
 11
 —
 11
Cross-currency derivatives —
 25
 —
 25
 —
 11
 —
 11
Foreign currency derivatives —
 35
 4
 39
 —
 16
 5
 21
 —
 46
 7
 53
 —
 16
 5
 21
Commodity derivatives —
 42
 1
 43
 —
 15
 2
 17
 —
 33
 1
 34
 —
 15
 2
 17
Total derivatives —
 314
 188
 502
 —
 263
 108
 371
 —
 303
 188
 491
 —
 263
 108
 371
TOTAL LIABILITIES $—
 $314
 $188
 $502
 $—
 $263
 $108
 $371
 $—
 $303
 $188
 $491
 $—
 $263
 $108
 $371
 _____________________________
(1) 
Amortized cost approximated fair value at JuneSeptember 30, 2014 and December 31, 2013.
The following tables present a reconciliation of net derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the three and sixnine months ended JuneSeptember 30, 2014 and 2013 (presented net by type of derivative). Transfers between Level 3 and Level 2 are determined as of the end of the reporting period and principally result from changes in the significance of unobservable inputs used to calculate the credit valuation adjustment.
 Three Months Ended June 30, 2014 Three Months Ended September 30, 2014
 
Interest
Rate
 
Foreign
Currency
 Commodity Total 
Interest
Rate
 
Foreign
Currency
 Commodity Total
 (in millions) (in millions)
Balance at the beginning of the period $(87) $101
 $—
 $14
 $(183) $107
 $16
 $(60)
Total gains (losses) (realized and unrealized):                
Included in earnings —
 10
 3
 13
 —
 (7) —
 (7)
Included in other comprehensive income - derivative activity (30) —
 —
 (30) (13) —
 —
 (13)
Included in other comprehensive income - foreign currency translation activity —
 (2) —
 (2) 9
 (4) —
 5
Included in regulatory (assets) liabilities —
 —
 15
 15
 —
 —
 (4) (4)
Settlements 3
 (2) (2) (1) 7
 (1) —
 6
Transfers of assets (liabilities) into Level 3 (69) —
 —
 (69)
Transfers of (assets) liabilities out of Level 3 —
 —
 —
 —
Balance at the end of the period $(183) $107
 $16
 $(60) $(180) $95
 $12
 $(73)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $—
 $9
 $—
 $9
 $—
 $(8) $—
 $(8)

7



 Three Months Ended June 30, 2013 Three Months Ended September 30, 2013
 
Interest
Rate
 
Foreign
Currency
 Commodity Total 
Interest
Rate
 
Foreign
Currency
 Commodity Total
 (in millions) (in millions)
Balance at the beginning of the period $(72) $71
 $(3) $(4) $(63) $70
 $9
 $16
Total gains (losses) (realized and unrealized):                
Included in earnings (4) 12
 1
 9
 (1) 28
 (1) 26
Included in other comprehensive income - derivative activity 13
 —
 —
 13
 7
 —
 —
 7
Included in other comprehensive income - foreign currency translation activity —
 (3) —
 (3) (1) (6) —
 (7)
Included in regulatory (assets) liabilities —
 —
 11
 11
 —
 —
 (4) (4)
Settlements 4
 (1) —
 3
 9
 (1) —
 8
Transfers of assets (liabilities) into Level 3 (42) —
 —
 (42) (84) —
 —
 (84)
Transfers of (assets) liabilities out of Level 3 38
 (9) —
 29
 30
 —
 —
 30
Balance at the end of the period $(63) $70
 $9
 $16
 $(103) $91
 $4
 $(8)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $—
 $14
 $—
 $14
 $—
 $27
 $(1) $26
 Six Months Ended June 30, 2014 Nine Months Ended September 30, 2014
 
Interest
Rate
 
Foreign
Currency
 Commodity Total 
Interest
Rate
 
Foreign
Currency
 Commodity Total
 (in millions) (in millions)
Balance at the beginning of the period $(101) $93
 $4
 $(4) $(101) $93
 $4
 $(4)
Total gains (losses) (realized and unrealized):                
Included in earnings 1
 37
 1
 39
 1
 29
 2
 32
Included in other comprehensive income - derivative activity (99) (1) —
 (100) (112) (2) —
 (114)
Included in other comprehensive income - foreign currency translation activity —
 (20) —
 (20) 9
 (24) —
 (15)
Included in regulatory (assets) liabilities —
 —
 12
 12
 —
 —
 7
 7
Settlements 16
 (3) (1) 12
 23
 (4) (1) 18
Transfers of (assets) liabilities out of Level 3 —
 1
 —
 1
 —
 3
 —
 3
Balance at the end of the period $(183) $107
 16
 $(60) $(180) $95
 12
 $(73)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period $1
 $34
 $—
 $35
 $1
 $26
 $1
 $28
Six Months Ended June 30, 2013Nine Months Ended September 30, 2013
Interest
Rate
 
Foreign
Currency
 Commodity Total
Interest
Rate
 
Foreign
Currency
 Commodity Total
(in millions)(in millions)
Balance at the beginning of the period$(412) $72
 $(1) $(341)$(412) $72
 $(1) $(341)
Total gains (losses) (realized and unrealized):              
Included in earnings(4) 15
 1
 12
(2) 40
 —
 38
Included in other comprehensive income - derivative activity81
 —
 —
 81
84
 —
 —
 84
Included in other comprehensive income - foreign currency translation activity2
 (6) —
 (4)(3) (12) —
 (15)
Included in regulatory (assets) liabilities—
 —
 10
 10
—
 —
 5
 5
Settlements48
 (2) (1) 45
73
 (3) —
 70
Transfers of (assets) liabilities out of Level 3222
 (9) —
 213
157
 (6) —
 151
Balance at the end of the period$(63) $70
 $9
 $16
$(103) $91
 $4
 $(8)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities held at the end of the period$—
 $13
 $1
 $14
$—
 $40
 $—
 $40
The following table summarizes the significant unobservable inputs used for the Level 3 derivative assets (liabilities) as of JuneSeptember 30, 2014:
Type of Derivative Fair Value Unobservable Input 
Amount or Range
(Weighted Average)
 Fair Value Unobservable Input 
Amount or Range
(Weighted Average)
 (in millions)   (in millions)  
Interest rate $(183) Subsidiaries’ credit spreads 3.75% - 5.30% (4.67%)
 $(180) Subsidiaries’ credit spreads 3.75% - 6.98% (5.51%)
Foreign currency:        
Embedded derivative — Argentine Peso 111
 Argentine Peso to U.S. Dollar currency exchange rate after 1 year 8.36 - 30.60 (20.06)
 102
 Argentine Peso to USD currency exchange rate after 1 year 8.84 - 36.40 (22.12)
Embedded derivative — Euro (4) Subsidiaries’ credit spreads 5.3% (7) Subsidiaries’ credit spreads 6.98%
Commodity:        
Other 16
   12
  
Total $(60)   $(73)  

8



Nonrecurring Measurements
When evaluating impairment of goodwill, long-lived assets, discontinued operations and held-for-sale businesses, and equity method investments, the Company measures fair value using the applicable fair value measurement guidance. Impairment expense is measured by comparing the fair value at the evaluation date to their then-latest available carrying amount. The following table summarizes major categories of assets and liabilities measured at fair value on a nonrecurring basis during the period and their level within the fair value hierarchy:
 Six Months Ended June 30, 2014 Nine Months Ended September 30, 2014
 
Carrying
Amount
 Fair Value 
Gross
Loss
 
Carrying
Amount (1)
 Fair Value 
Pretax
Loss
 Level 1 Level 2 Level 3  Level 1 Level 2 Level 3 
 (in millions) (in millions)
Assets                    
Long-lived assets held and used:(1)(2)
                    
DPL (East Bend) $14
 $—
 $2
 $—
 $12
 $14
 $—
 $2
 $—
 $12
Ebute 99
 —
 —
 47
 52
Ebute (measured at June 30, 2014) 99
 —
 —
 47
 52
Ebute (measured at September 30, 2014) 51
 —
 —
 36
 15
UK Wind (Newfield) 11
 —
 —
 —
 11
 11
 —
 —
 —
 11
Discontinued operations and held-for-sale businesses:(2)
          
Discontinued operations and held-for-sale businesses:(3)
          
Cameroon 372
 —
 340
 —
 38
 378
 —
 340
 —
 38
Equity method investments          
Equity method investments (5)
          
Silver Ridge Power 317
 —
 —
 273
 44
 315
 —
 —
 273
 42
Goodwill:(3)
          
Entek 143
 —
 125
 —
 18
Goodwill:(4)
          
DPLER 136
 —
 —
 —
 136
 136
 —
 —
 —
 136
Buffalo Gap 28
 —
 —
 10
 18
 28
 —
 —
 10
 18
 Six Months Ended June 30, 2013 Nine Months Ended September 30, 2013
 
Carrying
Amount
 Fair Value 
Gross
Loss
 
Carrying
Amount (1)
 Fair Value 
Pretax
Loss
 Level 1 Level 2 Level 3  Level 1 Level 2 Level 3 
 (in millions) (in millions)
Assets                    
Long-lived assets held and used:(1)(2)
                    
Poland Wind projects $79
 $—
 $—
 $14
 $65
Itabo (San Lorenzo) 22
 —
 —
 7
 15
Beaver Valley $61
 $—
 $—
 $15
 $46
 61
 —
 —
 15
 46
Long-lived assets held for sale:(1)
          
Long-lived assets held for sale:(2)
          
Wind turbines 25
 —
 25
 —
 —
 25
 —
 25
 —
 —
Discontinued operations and held-for-sale businesses:(2)
         

Ukraine utilities 143
 —
 113
 —
 34
Discontinued operations and held-for-sale businesses:(3)
         

Cameroon 264
 —
 199
 —
 65
Saurashtra 19
 —
 7
 —
 12
Ukraine 147
 —
 113
 —
 34
Equity method investments:(5)
          
Elsta 240
 —
 —
 118
 122
Goodwill (4)
          
Ebute 58
 —
 —
 —
 58
_____________________________
(1)
Represents the carrying value (including costs to sell) at the date of measurement, before fair value adjustment.
(2) 
See Note 15 — Asset Impairment Expense for further information.
(2)(3) 
See Note 1718 — Discontinued Operations and Held-For-Sale Businesses for further information. Also, the gross loss equals the carrying amount of the disposal group less its fair value less costs to sell.
(3)(4) 
See Note 14 — Goodwill ImpairmentsImpairment for further information.
(5)
See Note 16 —Other Non-Operating Expense and Note 7 — Investments in and Advances to Affiliates for further information.

9



The following table summarizes the significant unobservable inputs used in the Level 3 measurement of long-lived assets during the sixnine months ended JuneSeptember 30, 2014:
 Fair Value Valuation Technique Unobservable Input Range (Weighted  Average) Fair Value Valuation Technique Unobservable Input Range (Weighted Average)
 (in millions) ($ in millions) (in millions) ($ in millions)
Long-lived assets held and used:
        
Ebute $47
 Discounted cash flow Annual revenue growth
 0% to 1% (1%)
Ebute (June 30, 2014) $47
 Discounted cash flow Annual revenue growth
 0% to 1% (1%)
   Annual pretax operating margin 0% to 47% (24%)
   Annual pretax operating margin 0% to 47% (24%)
   Weighted-average cost of capital 10.3%
    
Ebute (September 30, 2014) $36
 Discounted cash flow Annual revenue growth
 0% to 1% (1%)
   Weighted-average cost of capital 10.3%   Annual pretax operating margin 0% to 56% (25%)
Equity Method Investment:        
Silver Ridge Power (1)
 273
 Discounted cash flow Annual revenue growth -57% to 1% (-4%)
 $273
 Discounted cash flow Annual revenue growth -57% to 1% (-4%)
   Annual pretax operating margin -115% to 50% (6%)
   Annual pretax operating margin -115% to 50% (6%)
   Cost of equity 13% to 16% (14%)
   Cost of equity 13% to 16% (14%)
Total $320
  
_____________________________
(1) The fair value for Silver Ridge Power was determined using a combination of the bid price (a level 2 input) obtained for the sale of AES’ interest in solar photovoltaic projects in operation and under development in Bulgaria, France, Greece, India and the United States, and a discounted cash flow model for the solar photovoltaic projects that were retained in Italy, Puerto Rico and Spain.
Financial Instruments not Measured at Fair Value in the Condensed Consolidated Balance Sheets
The following table sets forth the carrying amount, fair value and fair value hierarchy of the Company’s financial assets and liabilities that are not measured at fair value in the condensed consolidated balance sheets as of JuneSeptember 30, 2014 and December 31, 2013, but for which fair value is disclosed.

9



 
Carrying
Amount
 Fair Value 
Carrying
Amount
 Fair Value
 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3
 (in millions) (in millions)
June 30, 2014          
September 30, 2014          
Assets                    
Accounts receivable — noncurrent(1)
 $220
 $194
 $—
 $—
 $194
 $210
 $170
 $—
 $—
 $170
Liabilities                    
Non-recourse debt 15,940
 16,500
 —
 14,143
 2,357
 15,719
 16,117
 —
 13,818
 2,299
Recourse debt 5,783
 6,147
 —
 6,147
 —
 5,347
 5,598
 —
 5,598
 —
December 31, 2013                    
Assets                    
Accounts receivable — noncurrent(1)
 $260
 $194
 $—
 $—
 $194
 $260
 $194
 $—
 $—
 $194
Liabilities                    
Non-recourse debt 15,380
 15,620
 —
 13,397
 2,223
 15,380
 15,620
 —
 13,397
 2,223
Recourse debt 5,669
 6,164
 —
 6,164
 —
 5,669
 6,164
 —
 6,164
 —
_____________________________
(1) 
These accounts receivable principally relate to amounts due from CAMMESA, the administrator of the wholesale electricity market in Argentina, and are included in “Noncurrent assets — Other” in the accompanying condensed consolidated balance sheets.Condensed Consolidated Balance Sheets. The fair value and carrying amount of these accounts receivable exclude value-added tax of $3836 million and $46 million at JuneSeptember 30, 2014 and December 31, 2013, respectively.
4. INVESTMENTS IN MARKETABLE SECURITIES
The Company’s investments in marketable debt and equity securities as of JuneSeptember 30, 2014 and December 31, 2013 by security class and by level within the fair value hierarchy have been disclosed in Note 3 — Fair Value. The security classes are determined based on the nature and risk of a security and are consistent with how the Company manages, monitors and measures its marketable securities. As of JuneSeptember 30, 2014, $359$628 million of available-for-sale debt securities had stated maturities within one year and $17$31 million of available-for sale debt securities had stated maturities between one and twothree years. Gains and losses on the sale of investments are determined using the specific-identification method. Pretax gains and losses related to available-for-sale and trading securities are generally immaterial for disclosure purposes. For the three and sixnine months ended JuneSeptember 30, 2014 and 2013, there were no realized losses on the sale of available-for-sale securities and no other-than-temporary impairment of marketable securities was recognized in earnings or other comprehensive income. The following table summarizes the gross proceeds from sale of available-for-sale securities for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 2014 2013
  (in millions)
Gross proceeds from sales of available-for-sale securities $1,158
 $619
 $2,218
 $2,323
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 2014 2013
  (in millions)
Gross proceeds from sales of available-for-sale securities $1,144
 $1,071
 $3,362
 $3,394

10



5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
There have been no changes to the information disclosed under Derivatives and Hedging Activities in Note 1 — General and Summary of Significant Accounting Policies included in Item 8. — Financial Statements and Supplementary Data in the 2013 Form 10-K.
Volume of Activity
The following tables set forth, by type of derivative, the Company’s outstanding notional under its derivatives and the weighted-average remaining term as of JuneSeptember 30, 2014 regardless of whether the derivative instruments are in qualifying cash flow hedging relationships:
 Current Maximum   Current Maximum  
Interest Rate and Cross Currency 
Derivative
Notional
 Derivative Notional Translated to USD 
Derivative
Notional
 Derivative Notional Translated to USD Weighted-Average Remaining Term 
% of Debt Currently Hedged by Index(2)
Interest Rate and Cross-Currency 
Derivative
Notional
 Derivative Notional Translated to USD 
Derivative
Notional
 Derivative Notional Translated to USD Weighted-Average Remaining Term 
% of Debt Currently Hedged by Index(2)
 (in millions) (in years)   (in millions) (in years)  
Interest Rate Derivatives:(1)
                    
LIBOR (U.S. Dollar) 3,154
 $3,154
 4,886
 $4,886
 11 60% 2,943
 $2,943
 3,604
 $3,604
 11 57%
EURIBOR (Euro) 552
 756
 553
 757
 8 83% 551
 696
 551
 696
 7 86%
LIBOR (British Pound) 65
 111
 65
 111
 12 83%
Cross Currency Swaps:          
Cross-Currency Swaps:          
Chilean Unidad de Fomento 4
 191
 4
 191
 14 67% 4
 178
 4
 178
 14 67%
_____________________________
(1) 
The Company’s interest rate derivative instruments primarily include accreting and amortizing notionals. The maximum derivative notional represents the largest notional at any point between JuneSeptember 30, 2014 and the maturity of the derivative instrument, which includes forward-starting derivative instruments. The interest rate and cross currencycross-currency derivatives range in maturity through 2033 and 2028, respectively.
(2) 
The percentage of variable-rate debt currently hedged is based on the related index and excludes forecasted issuances of debt and variable-rate debt tied to other indices where the Company has no interest rate derivatives.

10



 June 30, 2014 September 30, 2014
Foreign Currency Derivatives 
Notional(1)
 Notional Translated to USD 
Weighted-Average Remaining Term (2)
 
Notional(1)
 Notional Translated to USD 
Weighted-Average Remaining Term (2)
 (in millions) (in years) (in millions) (in years)
Foreign Currency Options and Forwards:          
Chilean Unidad de Fomento 11
 $497
 1 10
 $398
 1
Chilean Peso 65,607
 119
 <1 117,734
 196
 <1
Brazilian Real 150
 68
 <1 119
 48
 <1
Euro 140
 192
 <1 103
 130
 <1
Colombian Peso 193,684
 103
 <1 78,230
 39
 <1
British Pound 61
 105
 <1 49
 79
 <1
Philippine Peso 672
 15
 <1
Embedded Foreign Currency Derivatives:          
Argentine Peso 809
 99
 10 904
 107
 10
Kazakhstani Tenge 4,783
 26
 2 4,802
 26
 1
Brazilian Real 81
 37
 <1
_____________________________
(1) 
Represents contractual notionals. The notionals for options have not been probability adjusted, which generally would decrease them.
(2) 
Represents the remaining tenor of our foreign currency derivatives weighted by the corresponding notional. These options and forwards and these embedded derivatives range in maturity through 2017 and 2025, respectively.
 June 30, 2014 September 30, 2014
Commodity Derivatives Notional 
Weighted-Average Remaining Term(1)
 Notional 
Weighted-Average Remaining Term(1)
 (in millions) (in years) (in millions) (in years)
Power (MWh) 2
 3 6
 2
Coal (Metric tons) 1
 2 1
 1
_____________________________
(1) Represents the remaining tenor of our commodity derivatives weighted by the corresponding volume. These derivatives range in maturity through 2016.
Accounting and Reporting
Assets and Liabilities
The following tables set forth the fair values of the Company’s derivative instruments as of JuneSeptember 30, 2014 and December 31, 2013, first by whether or not they are designated hedging instruments, then by whether they are current or noncurrent to the extent they are subject to master netting agreements or similar agreements (where the rights to set-off relate to settlement of amounts receivable and payable under those derivatives) and by balances no longer accounted for as derivatives.
  June 30, 2014 December 31, 2013
  Designated Not Designated Total Designated Not Designated Total
  (in millions)
Assets            
Interest rate derivatives $20
 $2
 $22
 $96
 $2
 $98
Cross currency derivatives —
 —
 —
 5
 —
 5
Foreign currency derivatives 5
 121
 126
 4
 109
 113
Commodity derivatives 33
 31
 64
 8
 16
 24
Total assets $58
 $154
 $212
 $113
 $127
 $240
Liabilities            
Interest rate derivatives $406
 $3
 $409
 $318
 $4
 $322
Cross currency derivatives 11
 —
 11
 11
 —
 11
Foreign currency derivatives 29
 10
 39
 15
 6
 21
Commodity derivatives 25
 18
 43
 7
 10
 17
Total liabilities $471
 $31
 $502
 $351
 $20
 $371
  June 30, 2014 December 31, 2013
  Assets Liabilities Assets Liabilities
  (in millions)
Current $73
 $185
 $32
 $157
Noncurrent 139
 317
 208
 214
Total $212
 $502
 $240
 $371
Derivatives subject to master netting agreement or similar agreement:        
Gross amounts recognized in the balance sheet $69
 $484
 $91
 $314
Gross amounts of derivative instruments not offset (18) (18) (9) (9)
Gross amounts of cash collateral received/pledged not offset —
 (19) (3) (6)
Net amount $51
 $447
 $79
 $299
Other balances that had been, but are no longer, accounted for as derivatives that are to be amortized to earnings over the remaining term of the associated PPA $163
 $185
 $169
 $190


11



  September 30, 2014 December 31, 2013
  Designated Not Designated Total Designated Not Designated Total
  (in millions)
Assets            
Interest rate derivatives $20
 $—
 $20
 $96
 $2
 $98
Cross-currency derivatives —
 —
 —
 5
 —
 5
Foreign currency derivatives 10
 121
 131
 4
 109
 113
Commodity derivatives 18
 23
 41
 8
 16
 24
Total assets $48
 $144
 $192
 $113
 $127
 $240
Liabilities            
Interest rate derivatives $377
 $2
 $379
 $318
 $4
 $322
Cross-currency derivatives 25
 —
 25
 11
 —
 11
Foreign currency derivatives 42
 11
 53
 15
 6
 21
Commodity derivatives 18
 16
 34
 7
 10
 17
Total liabilities $462
 $29
 $491
 $351
 $20
 $371
  September 30, 2014 December 31, 2013
  Assets Liabilities Assets Liabilities
  (in millions)
Current $65
 $165
 $32
 $157
Noncurrent 127
 326
 208
 214
Total $192
 $491
 $240
 $371
Derivatives subject to master netting agreement or similar agreement:        
Gross amounts recognized in the balance sheet $57
 $469
 $91
 $314
Gross amounts of derivative instruments not offset (12) (12) (9) (9)
Gross amounts of cash collateral received/pledged not offset —
 (14) (3) (6)
Net amount $45
 $443
 $79
 $299
Other balances that had been, but are no longer, accounted for as derivatives that are to be amortized to earnings over the remaining term of the associated PPA $161
 $183
 $169
 $190
Effective Portion of Cash Flow Hedges
The following tables set forth the pretax gains (losses) recognized in accumulated other comprehensive loss (“AOCL”) and earnings related to the effective portion of derivative instruments in qualifying cash flow hedging relationships (including amounts that were reclassified from AOCL as interest expense related to interest rate derivative instruments that previously, but no longer, qualify for cash flow hedge accounting), as defined in the accounting standards for derivatives and hedging, for the periods indicated:
 Gains (Losses) Recognized in AOCL   Gains (Losses) Reclassified from AOCL into Earnings Gains (Losses) Recognized in AOCL   Gains (Losses) Reclassified from AOCL into Earnings
 Three Months Ended June 30, Classification in Condensed Consolidated Statements of Operations Three Months Ended June 30, Three Months Ended September 30, Classification in Condensed Consolidated Statements of Operations Three Months Ended September 30,
Type of Derivative 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions) (in millions) (in millions)
Interest rate derivatives $(124) $134
 Interest expense $(33) $(31) $(16) $10
 Interest expense $(38) $(32)
     Non-regulated cost of sales —
 (1)     Non-regulated cost of sales (1) (1)
     Net equity in earnings of affiliates (2) (2)     Net equity in earnings of affiliates —
 (1)
     Gain on sale of investments —
 (21)
Cross currency derivatives —
 (12) Interest expense 2
 (3)
Cross-currency derivatives (17) 2
 Interest expense (1) (4)
     Foreign currency transaction gains (losses) 4
 (19)     Foreign currency transaction gains (losses) (18) 4
Foreign currency derivatives 3
 1
 Foreign currency transaction gains (losses) 3
 2
 (12) (1) Foreign currency transaction gains (losses) 1
 3
Commodity derivatives (6) 7
 Non-regulated revenue 6
 (1) 3
 (4) Non-regulated revenue 4
 (3)
 

 

 Non-regulated cost of sales (3) —
 

 

 Non-regulated cost of sales (1) (1)
Total $(127) $130
 $(23) $(76) $(42) $7
 $(54) $(35)

12



 Gains (Losses) Recognized in AOCL   Gains (Losses) Reclassified from AOCL into Earnings Gains (Losses) Recognized in AOCL   Gains (Losses) Reclassified from AOCL into Earnings
 Six Months Ended June 30, Classification in Condensed Consolidated Statements of Operations Six Months Ended June 30, Nine Months Ended September 30, Classification in Condensed Consolidated Statements of Operations Nine Months Ended September 30,
Type of Derivative 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions) (in millions) (in millions)
Interest rate derivatives $(274) $121
 Interest expense $(64) $(63) $(290) $131
 Interest expense $(102) $(95)
     Non-regulated cost of sales (1) (2)     Non-regulated cost of sales (2) (3)
     Net equity in earnings of affiliates (3) (4)     Net equity in earnings of affiliates (3) (5)
     Gain on sale of investments —
 (21)     Gain on sale of investments —
 (21)
Cross currency derivatives (3) (11) Interest expense 1
 (6)
Cross-currency derivatives (20) (9) Interest expense —
 (10)
     Foreign currency transaction gains (losses) (6) (14)     Foreign currency transaction gains (losses) (24) (10)
Foreign currency derivatives (12) 2
 Foreign currency transaction gains (losses) 10
 4
 (24) 1
 Foreign currency transaction gains (losses) 11
 7
Commodity derivatives 18
 2
 Non-regulated revenue 19
 (1) 21
 (2) Non-regulated revenue 23
 (4)
     Non-regulated cost of sales (1) —
     Non-regulated cost of sales (2) (1)
Total $(271) $114
 $(45) $(107) $(313) $121
 $(99) $(142)
The pretax accumulated other comprehensive income (loss) expected to be recognized as an increase (decrease) to income from continuing operations before income taxes over the next twelve months as of JuneSeptember 30, 2014 is $(117)(111) million for interest rate hedges, $(4) million for cross currencycross-currency swaps, $(5)9 million for foreign currency hedges, and $(6)(1) million for commodity and other hedges.
For the three and nine months ended JuneSeptember 30, 2014, and June 30, 2013, pretax gains of $6$0 million and $0$6 million, net of noncontrolling interests, respectively, were reclassified into earnings as a result of the discontinuance of a cash flow hedge. Hedge accounting was discontinued as the forecasted transaction would not occur by the end of the originally specified time period (as documented at the inception of the hedging relationship) or within an additional two-month time period thereafter. There were no such items for the three and nine months ended September 30, 2013.
Ineffective Portion of Cash Flow Hedges
The following table sets forth the pretax gains (losses) recognized in earnings related to the ineffective portion of derivative instruments in qualifying cash flow hedging relationships, as defined in the accounting standards for derivatives and hedging, for the periods indicated:
 Gains (Losses) Recognized in Earnings Gains (Losses) Recognized in Earnings
 Classification in Condensed Consolidated Statements of Operations Three Months Ended June 30, Six Months Ended June 30, Classification in Condensed Consolidated Statements of Operations Three Months Ended September 30, Nine Months Ended September 30,
Type of Derivative 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
Interest rate derivatives Interest expense $1
 $31
 $1
 $30
 Interest expense $(1) $(1) $—
 $29
Cross currency derivatives Interest expense (1) —
 (1) —
Foreign currency derivatives
 Foreign currency transaction gains (losses)
 (2) —
 $(2) $—
Cross-currency derivatives Interest expense —
 —
 (1) —
Commodity and other derivatives Non-regulated revenue —
 —
 —
 —
 Non-regulated revenue 1
 —
 1
 —
 Non-regulated cost of sales —
 —
 —
 —
Total $—
 $31
 $—
 $30
 $(2) $(1) $(2) $29


12



Not Designated for Hedge Accounting
The following table sets forth the gains (losses) recognized in earnings related to derivative instruments not designated as hedging instruments under the accounting standards for derivatives and hedging and the amortization of balances that had been, but are no longer, accounted for as derivatives, for the periods indicated:
 Gains (Losses) Recognized in Earnings Gains (Losses) Recognized in Earnings
 Classification in Condensed Consolidated Statements of Operations Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,		 Classification in Condensed Consolidated Statements of Operations Three Months Ended 
 September 30,		 Nine Months Ended 
 September 30,
Type of Derivative 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
Interest rate derivatives Interest expense $—
 $1
 $—
 $2
 Interest expense $(1) $(1) $(1) $1
 Net equity in earnings of affiliates —
 —
 —
 (6) Net equity in earnings of affiliates —
 —
 —
 (6)
Foreign currency derivatives Foreign currency transaction gains (losses) 6
 17
 29
 23
 Foreign currency transaction gains (losses) 2
 24
 31
 47
 Net equity in earnings of affiliates 9
 (12) 5
 (15) Net equity in earnings of affiliates (9) (7) (4) (22)
Commodity and other derivatives Non-regulated revenue 1
 12
 4
 4
 Non-regulated revenue (2) 4
 2
 8
 Regulated revenue —
 3
 —
 —
 Non-regulated cost of sales (3) (2) (1) (1)
 Non-regulated cost of sales 2
 —
 2
 1
 Regulated cost of sales (4) 1
 (10) 12
 Regulated cost of sales 2
 11
 (6) 11
 Income (loss) from operations of discontinued businesses —
 2
 (7) (10)
 Income (loss) from operations of discontinued businesses (2) 1
 (7) (12) Net loss from disposal and impairments of discontinued businesses —
 —
 72
 —
 Net loss from disposal and impairments of discontinued businesses 72
 —
 72
 —
Total $90
 $33
 $99
 $8
 $(17) $21
 $82
 $29

13



Credit Risk-Related Contingent Features
DP&L, a utility within our United States strategic business unit, has certain over-the-counter commodity derivative contracts under master netting agreements that contain provisions that require DP&L to maintain an investment-grade issuer credit rating from credit rating agencies. Since DP&L's rating has fallen below investment grade, certain of the counterparties to the derivative contracts have requested immediate and ongoing full overnight collateralization of the mark-to-market loss (fair value excluding credit valuation adjustments), which was $3528 million and $11 million as of JuneSeptember 30, 2014 and December 31, 2013, respectively, for all derivatives with credit risk-related contingent features. As of JuneSeptember 30, 2014 and December 31, 2013, DP&L had posted $1914 million and $6 million, respectively, of cash collateral directly with third parties and in a broker margin account and DP&L held no cash collateral from counterparties to its derivative instruments that were in an asset position. After consideration of the netting of counterparty assets, DP&L could have been required to, but did not, provide additional collateral of $54 million and $0 million as of JuneSeptember 30, 2014 and December 31, 2013, respectively.
6. FINANCING RECEIVABLES
Financing receivables are defined as receivables that have contractual maturities of greater than one year. The Company has financing receivables pursuant to amended agreements or government resolutions that are due from certain Latin American governmental bodies, primarily in Argentina. The following table sets forth the breakdown of financing receivables by country as of the periods indicated:
 June 30, 2014 December 31, 2013 September 30, 2014 December 31, 2013
 (in millions) (in millions)
Argentina(1)
 $138
 $164
 $131
 $164
Dominican Republic 1
 2
 1
 2
Brazil 14
 18
 11
 18
Total long-term financing receivables $153
 $184
 $143
 $184
_____________________________
(1) 
Total receivables with the Argentine government were $243$234 million and $286 million, respectively, as of JuneSeptember 30, 2014 and December 31, 2013. The amounts presented in the table above exclude noncurrent receivables of $105$103 million and $122$122 million,, respectively, as of JuneSeptember 30, 2014 and December 31, 2013,, which have not been converted into financing receivables and do not have contractual maturities of greater than one year. Of the $105$103 million,, approximately $82$76 million is expected to be contributed to a FONINVEMEM Agreement and approximately $23$27 million is expected to be contributed to a trust to be set up by the Argentine government as required by Resolution 95. Also, excludes the foreign currency-related embedded derivative assets associated with the financing receivables which had a fair value of $111$102 million and $97 million, respectively, as of JuneSeptember 30, 2014 and December 31, 2013.
Argentina—As a result of energy market reforms in 2004 and consistent with contractual arrangements, AES Argentina entered into three agreements with the Argentine government called (as translated into English) the Fund for the Investment Needed to Increase the Supply of Electricity in the Wholesale Market (“FONINVEMEM Agreements”) to contribute a portion of their accounts receivable into a fund for financing the construction of combined cycle and gas-fired plants. These receivables accrue interest and are collected in monthly installments over 10 years once the related plant begins operations. In addition, AES Argentina receives an ownership interest in these newly built plants once the receivables have been fully repaid. Collection of the principal and interest on these receivables is subject to various business risks and uncertainties including, but not limited to, the completion and operation of power plants which generate cash for payments of these receivables, regulatory

13



changes that could impact the timing and amount of collections, and economic conditions in Argentina. The Company monitors these risks including the credit ratings of the Argentine government on a quarterly basis to assess the collectability of these receivables. The Company accrues interest on these receivables once the recognition criteria have been met. The Company’s collection estimates are based on assumptions that it believes to be reasonable but are inherently uncertain. Actual future cash flows could differ from these estimates. The receivables under the first two FONINVEMEM Agreements are being actively collected since the related plants commenced operations in 2010. In assessing the collectability of the receivables under these agreements, the Company also considers how the collections have historically been made timely in accordance with the agreements. The receivables related to the third FONINVEMEM Agreement are not currently due as commercial operation of the two related gas-fired plants has not been achieved. In assessing the collectability of the receivables under this agreement, the Company also considers the extent to which significant milestones necessary to complete the plants have been achieved or are still probable.
In March 2013, the Argentine government passed Resolution No. 95/2013 ("Resolution 95") to introduce a new energy regulatory framework. Applicable to the majority of generation companies, the new regulatory framework remunerates the fixed and variable costs plus a margin depending on the type of fuel consumed and technology used. On May 31, 2013, Resolution 95 became effective retroactively to February 1, 2013. CAMMESA, the administrator of the wholesale electricity market in Argentina, has been billing the generation companies in accordance with the Resolution 95 procedures since June 2013. In addition, Resolution 95 determines the portion of future outstanding receivables that shall be contributed into the new trusts to be set up by the Argentine government. In March 2014, AES Argentina signed a framework agreement with the Secretary of Energy that outlines a plan to make an investment in new energy capacity in which AES Argentina will maintain

14



100% ownership, utilizing Resolution 95 new trust receivables to be accumulated through December 31, 2015.June 30, 2016. Terms and conditions of this plan are still being negotiated. In May 2014, the Argentine government passed a modification to Resolution 95 named Resolution No. 529/2014 ("Resolution 529"), which is retroactive to February 2014 and updates the remuneration amounts agreed upon in Resolution 95 and creates a new payment provision for major maintenance activities.
7. INVESTMENTS IN AND ADVANCES TO AFFILIATES
Summarized Financial Information
The following tables summarizetable summarizes financial information of the Company’s 50%-or-less owned-or-less-owned affiliates that are accounted for using the equity method.
50%-or-less Owned AffiliatesNine Months Ended September 30,
For the Six months ended June 30,2014 2013
50%-or-less-Owned Affiliates2014 2013
(in millions)(in millions)
Revenue$568
 $624
$716
 $830
Operating margin150
 150
159
 191
Net income107
 13
89
 (9)
Silver Ridge Power
On July 2, 2014, the Company entered into a binding agreement to sell its 50% ownership interest in Silver Ridge Power, LLC (“SRP”) for a purchase price of $179 million, excluding the Company’s indirect ownership interests in SRP’s solar generation businesses in Italy, Puerto Rico and Spain. On July 1, 2014, the Puerto Rico business was distributed by SRP to AES and Riverstone Holdings LLC and is now accounted for as an equity method investment with both AES and Riverstone Holdings each having a 50% ownership. The buyer also has an option to purchase the Company's indirect 50% interest in the Italy solar generation business for an additional consideration of $42 million by August 2015.
Currently, this transaction does not qualify as a sale for accounting purposes as the Company has continuing involvement in the business operations. Once the Company ceases its involvement in SRP's business operations, the transaction will then be considered a sale of real estate. As the Company no longer retains a direct equity interest in SRP, the remaining balance of $32 million related to Italy and Spain, which was previously accounted for as part of our equity method investment in SRP, and the accumulated other comprehensive income balance of $40 million, related to the Company's investment in SRP, have been reclassified to "Other noncurrent assets" on the Condensed Consolidated Balance Sheet as of September 30, 2014.
Guacolda
On April 11, 2014, AES Gener undertook a series of transactions, pursuant to which AES Gener acquired the interests it did not previously own in Guacolda for $728 million and simultaneously sold the ownership interest to Global Infrastructure Partners ("GIP") for $730 million. The transaction provided GIP with substantive participating rights in Guacolda, and, as a result, the Company continues to account for its investment in Guacolda using the equity method of accounting. The cash outflow for the acquisition is reflected in "Acquisitions - net of cash acquired" and the cash inflow from the sale of these ownership interests to GIP is reflected in "Proceeds from the sale of businesses, net of cash sold" on the Condensed Consolidated Statement of Cash Flows for the period ended September 30, 2014.
8. DEBT
Recourse Debt
In February 2014, the Company redeemed in full the $110 million balance of its 7.75% senior unsecured notes due March 2014. On March 7, 2014, the Company issued $750 million aggregate principal amount of 5.50% senior notes due 2024. Concurrent with this offering, the Company redeemed via tender offers $625 million aggregate principal of its existing 8.00% senior unsecured notes due 2017. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $132 million that is included in the Condensed Consolidated Statement of Operations.
On May 20, 2014, the Company issued $775 million aggregate principal amount of senior unsecured floating rate notes due June 2019. The notes bear interest at a rate of 3% above three-month LIBOR, reset quarterly. Concurrent with this offering, the Company repaid $767 million of its existing senior secured term loan due 2018. As a result of the latter transaction, the Company recognized a loss on extinguishment of debt of $10 million that is included in the Condensed Consolidated Statement of Operations. On June 16, 2014, the Company repaid in full the remaining balance of $29 million of its senior secured term loan due 2018.

14



On July 25, 2014, the Company issued two notices to call $320 million aggregate principal amount of unsecured notes, $160 million of which willwas used to retire notes due in 2015 and $160 million of which willwas used to retire notes due in 2016. The Company anticipates closing theclosed these transactions on August 25, 2014. As a result of this transaction, the Company recognized a loss on extinguishment of debt of $40 million that is included in the Condensed Consolidated Statement of Operations.

15



Non-Recourse Debt
Significant transactions
During the sixnine months ended JuneSeptember 30, 2014, the Company's subsidiaries had the following significant debt transactions:
Mong Duong drew $272$298 million under its construction loan facility;
Gener issued new debt of $700 million, more than offset by repayments of$853of $905 million;
Eletropaulo issued new debt of $253 million;
IPL issued new debt of $130 million;
Tietê issued new debt of $129 million, more than offset by repayments of $132 million;
Cochrane drew$125drew $173 million under its construction loans;
Sul issued new debt of $111 million; and
Alto Maipo drew $103$105 million under its existing construction loans.
Debt in default
The following table summarizes the Company’s subsidiary non-recourse debt in default or accelerated as of the period indicated. The debt is classified as current non-recourse debt unless otherwise indicated:
 
Primary Nature
of Default
 June 30, 2014 
Primary Nature
of Default
 September 30, 2014
Subsidiary Default Amount Net Assets Default Amount Net Assets
 (in millions) (in millions)
Maritza (Bulgaria) Covenant $815
 $572
 Covenant $720
 $569
Kavarna (Bulgaria) Covenant 195
 88
 Covenant 176
 78
 $1,010
   $896
  
The above defaults are not payment defaults, but are instead defaults triggered by failure to comply with other covenants and/or other conditions such as (but not limited to) failure to meet information covenants, complete construction or other milestones in an allocated time, meet certain minimum or maximum financial ratios, or other requirements contained in the non-recourse debt documents of the borrower.
In addition, in the event that there is a default, bankruptcy or maturity acceleration at a subsidiary or group of subsidiaries that meets the applicable definition of materiality under the corporate debt agreements of The AES Corporation, there could be a cross-default to the Company’s recourse debt. Materiality is defined in the Parent's senior secured credit facility as having provided 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of JuneSeptember 30, 2014, none of the defaults listed above individually or in the aggregate result in or are at risk of triggering a cross-default under the recourse debt of the Parent Company. In the event the Parent Company is not in compliance with the financial covenants of its senior secured revolving credit facility, restricted payments will be limited to regular quarterly shareholder dividends at the then-prevailing rate. Additionally, payment defaults and bankruptcy defaults also preclude the making of any restricted payments.
Interest Expense
Interest expense for the threenine months ended JuneSeptember 30, 2014 has been reduced by approximately $48 million related to contingent interest accruals associated with disputed purchased energy obligations at Sul for which it was determined based on developments withinduring the currentsecond quarter that the likelihood of an unfavorable outcome for the payment of interest on the disputed obligations was no longer probable. Interest expense for the threenine months ended JuneSeptember 30, 2013 has been reduced by approximately $34 million related to the recognition of ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges.
9. CONTINGENCIES AND COMMITMENTS
Guarantees, Letters of Credit and Commitments
In connection with certain project financing, acquisition, power purchase and other agreements, the Parent Company has expressly undertaken limited obligations and commitments, most of which will only be effective or will be terminated upon the occurrence of future events. In the normal course of business, the Parent Company has entered into various agreements, mainly guarantees and letters of credit, to provide financial or performance assurance to third parties on behalf of AES businesses. These agreements are entered into primarily to support or enhance the creditworthiness otherwise achieved by a business on a stand-alone basis, thereby facilitating the availability of sufficient credit to accomplish their intended business purposes. Most

15



of the contingent obligations relate to future performance commitments which the Company or its businesses expect to fulfill

16



within the normal course of business. The expiration dates of these guarantees vary from less than one year to more than 19 years. The following table summarizes the Parent Company’s contingent contractual obligations as of JuneSeptember 30, 2014. Amounts presented in the table below represent the Parent Company’s current undiscounted exposure to guarantees and the range of maximum undiscounted potential exposure. The maximum exposure is not reduced by the amounts, if any, that could be recovered under the recourse or collateralization provisions in the guarantees. The amounts include obligations made by the Parent Company for the direct benefit of the lenders associated with the non-recourse debt of its businesses of $24 million.
Contingent Contractual Obligations Amount 
Number of
Agreements
 
Maximum Exposure Range for
Each Agreement
 Amount 
Number of
Agreements
 
Maximum Exposure Range for
Each Agreement
 (in millions)   (in millions) (in millions)   (in millions)
Guarantees and commitments $333
 16
 <$1 - 53 $329
 15
 $1 - 53
Asset sale related indemnities 287
 5
 $2 - 209 718
 6
 $2 - 285
Cash collateralized letters of credit 102
 11
 <$1 - 63 97
 11
 <$1 - 58
Letters of credit under the senior secured credit facility 1
 2
 <$1 1
 2
 <$1
Total $723
 34
  $1,145
 34
 
During the three months ended JuneSeptember 30, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts of letters of credit.
Environmental
The Company periodically reviews its obligations as they relate to compliance with environmental laws, including site restoration and remediation. As of JuneSeptember 30, 2014 and December 31, 2013, the Company had recordedrecognized liabilities of $1712 million and $19 million, respectively, for projected environmental remediation costs. Due to the uncertainties associated with environmental assessment and remediation activities, future costs of compliance or remediation with current legislation or costs for new legislation introduced could be higher or lower than the amount currently accrued. Moreover, where no liability has been recognized, it is reasonably possible that the Company may be required to incur remediation costs or make expenditures in amounts that could be material but could not be estimated as of JuneSeptember 30, 2014. In aggregate, the Company estimates that the range of potential losses related to environmental matters, where estimable, to be from $1 million up to $36 million. The amounts considered reasonably possible do not include amounts accrued as discussed above.
Litigation
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company accrues for litigation and claims when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company has evaluated claims in accordance with the accounting guidance for contingencies that it deems both probable and reasonably estimable and, accordingly, has recordedrecognized aggregate liabilities for all claims of approximately $238258 million and $239 million as of JuneSeptember 30, 2014 and December 31, 2013, respectively. These amounts are reported on the condensed consolidated balance sheetsCondensed Consolidated Balance Sheets within “accrued and other liabilities” and “other noncurrent liabilities.” A significant portion of these accrued liabilities relate to employment, non-income tax and customer disputes in international jurisdictions, principally Brazil. Certain of the Company’s subsidiaries, principally in Brazil, are defendants in a number of labor and employment lawsuits. The complaints generally seek unspecified monetary damages, injunctive relief, or other relief. The subsidiaries have denied any liability and intend to vigorously defend themselves in all of these proceedings. There can be no assurance that these accrued liabilities will be adequate to cover all existing and future claims or that we will have the liquidity to pay such claims as they arise.
The Company believes, based upon information it currently possesses and taking into account established accruals for liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material effect on the Company’s consolidated financial statements. However, where no accrued liability has been recognized, it is reasonably possible that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but could not be estimated as of JuneSeptember 30, 2014. The material contingencies where a loss is reasonably possible primarily include: claims under financing agreements; disputes with offtakers, suppliers and EPC contractors; alleged violation of monopoly laws and regulations; income tax and non-income tax matters with tax authorities; and regulatory matters. In aggregate, the Company estimates that the range of potential losses, where estimable, related to these reasonably possible material contingencies to be between $1.21.1 billion and $1.81.4 billion. Certain claims are in settlement negotiations. The amounts considered reasonably possible do not include amounts accrued, as discussed above. These material contingencies do not include income tax-related contingencies which are considered part of our uncertain tax positions.

1617



10. PENSION PLANS
Total pension cost for the periods indicated included the following components:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 U.S. Foreign U.S. Foreign U.S. Foreign U.S. Foreign U.S. Foreign U.S. Foreign U.S. Foreign U.S. Foreign
 (in millions) (in millions)
Service cost $4
 $4
 $4
 $6
 $7
 $8
 $8
 $13
 $3
 $5
 $4
 $6
 $10
 $13
 $12
 $20
Interest cost 12
 129
 11
 134
 24
 251
 22
 273
 12
 126
 11
 122
 36
 377
 33
 394
Expected return on plan assets (16) (96) (16) (127) (32) (186) (31) (257) (17) (93) (15) (114) (49) (279) (46) (371)
Amortization of prior service cost 1
 1
 2
 —
 3
 2
 3
 —
 2
 —
 1
 —
 5
 2
 4
 —
Amortization of net loss 3
 9
 7
 22
 6
 17
 14
 42
 4
 9
 7
 18
 10
 26
 21
 59
Total pension cost $4
 $47
 $8
 $35
 $8
 $92
 $16
 $71
 $4
 $47
 $8
 $32
 $12
 $139
 $24
 $102
Total employer contributions for the sixnine months ended JuneSeptember 30, 2014 for the Company’s U.S. and foreign subsidiaries were $5556 million and $80110 million, respectively. The expected remaining scheduled employer contributions for 2014 are $10 million and $5828 million for U.S. and foreign subsidiaries, respectively.
11. EQUITY
Changes in Equity
The following table provides a reconciliation of the beginning and ending equity attributable to stockholders of The AES Corporation, noncontrolling interests and total equity as of the periods indicated:
 Six Months Ended June 30, 2014 Six Months Ended June 30, 2013 Nine Months Ended September 30, 2014 Nine Months Ended September 30, 2013
 The AES Corporation Stockholders’ Equity 
Noncontrolling
Interests
 
Total
Equity
 The AES Corporation Stockholders’ Equity 
Noncontrolling
Interests
 
Total
Equity
 The AES Corporation Stockholders’ Equity 
Noncontrolling
Interests
 
Total
Equity
 The AES Corporation Stockholders’ Equity 
Noncontrolling
Interests
 
Total
Equity
 (in millions) (in millions)
Balance at the beginning of the period $4,330
 $3,321
 $7,651
 $4,569
 $2,945
 $7,514
 $4,330
 $3,321
 $7,651
 $4,569
 $2,945
 $7,514
Net income (loss) 75
 266
 341
 249
 283
 532
Net income 563
 286
 849
 320
 435
 755
Total change in fair value of available-for-sale securities, net of income tax (1) —
 (1) —
 —
 —
Total foreign currency translation adjustment, net of income tax (56) 38
 (18) (148) (69) (217) (269) (82) (351) (158) (65) (223)
Total change in derivative fair value, net of income tax (99) (94) (193) 123
 48
 171
 (79) (106) (185) 151
 54
 205
Total pension adjustments, net of income tax 14
 17
 31
 6
 21
 27
 15
 21
 36
 9
 30
 39
Balance sheet reclassification related to an equity method investment (1)
 40
 —
 40
 —
 —
 —
Capital contributions from noncontrolling interests —
 113
 113
 —
 55
 55
 —
 131
 131
 —
 86
 86
Distributions to noncontrolling interests —
 (215) (215) —
 (226) (226) —
 (380) (380) —
 (382) (382)
Disposition of businesses —
 (151) (151) (1) (20) (21) —
 (152) (152) —
 (20) (20)
Acquisition of treasury stock (32) —
 (32) (18) —
 (18) (140) —
 (140) (63) —
 (63)
Issuance and exercise of stock-based compensation benefit plans, net of income tax 16
 —
 16
 24
 —
 24
 23
 —
 23
 39
 —
 39
Dividends declared on common stock ($0.05 per share) (36) —
 (36) (60) —
 (60)
Dividends declared on common stock (2)
 (72) —
 (72) (60) —
 (60)
Sale of subsidiary shares to noncontrolling interests —
 —
 —
 11
 22
 33
 —
 130
 130
 12
 71
 83
Transaction between entities under common control 5
 2
 7
 —
 —
 —
Acquisition of subsidiary shares from noncontrolling interests (6) —
 (6) (6) (1) (7) (13) —
 (13) (6) (1) (7)
Balance at the end of the period $4,211
 $3,297
 $7,508
 $4,749
 $3,058
 $7,807
 $4,397
 $3,169
 $7,566
 $4,813
 $3,153
 $7,966
_____________________________
(1)Reclassification resulting from Silver Ridge Power transaction. See Note 7 — Investments In and Advances to Affiliates for further information.
(2) Dividends price per share was $0.10 and $0.08 as of September 30, 2014 and September 30, 2013, respectively.
Equity Transactions with Noncontrolling Interests
Dominican Republic — In September 2014, the Company executed an agreement with the Estrella-Linda group, an investor-based group in the Dominican Republic, to form a strategic partnership. Under the terms of the agreement, Estrella Linda will acquire an 8% noncontrolling interest in our businesses in the Dominican Republic for $96 million, with an option to acquire an additional 2% for $24 million at any time between closing date and December 31, 2015, and an additional 10% for $125 million at any time between closing date and December 31, 2016. The transaction is expected to close during the fourth quarter of 2014, subject to customary closing conditions. The Company is still evaluating the fourth quarter accounting implications of this transaction.
Masinloc — On June 25, 2014, the Company executed an agreement to sell approximately 45% of its interest in Masin-AES Pte Ltd., a wholly-owned subsidiary that owns the Company's business interests in the Philippines, for $453 million, subject to certain purchase price adjustments. On July 15, 2014, the Company completed the Masinloc sale transaction and received net proceeds of $453$443 million, including $23 million contingent upon the achievement of certain restructuring

18



efficiencies. The proceedstransaction was accounted for as a sale of $453real estate. Noncontrolling interest of $130 million areand a pretax gain of approximately $300$283 million, in excessnet of the carrying amount at June 30, 2014transaction costs, was recognized as a gain on sale of the Company’s 45% interest in Masin-AESPte Ltd. The sale includes indirect interests in the 630 MW Masinloc coal-fired power plant, ongoing Masinloc facility expansion projects, and approximately 60 MW of potential energy storage projects in advanced development. The Company is currently evaluatinginvestment during the third quarter 2014 accounting implications of this sale.2014. The portion of the gain related to the contingency has been deferred.
After completion of the sale, the Company continues to own a 51% net ownership interest in Masinloc and will continue to manage and operate the plant, with 41% owned by Electricity Generating Public Company Limited (EGCO Group) and 8% owned by the International Finance Corporation (IFC). As the Company maintained control after the sale, Masinloc will continue to be accounted for as a consolidated subsidiary within the Asia SBU reportable segment.

17



Accumulated Other Comprehensive Loss
The changes in accumulated other comprehensive lossAOCL by component, net of tax and noncontrolling interests for the sixnine months ended JuneSeptember 30, 2014 were as follows:
  Unrealized derivative losses, net Unfunded pension obligations, net Foreign currency translation adjustment, net Total
  (in millions)
Balance at the beginning of the period $(307) $(291) $(2,284) $(2,882)
Other comprehensive income before reclassifications (116) 9
 (9) (116)
Amounts reclassified from accumulated other comprehensive loss 17
 5
 (47) (25)
Net current-period other comprehensive income (99) 14
 (56) (141)
Balance at the end of the period $(406) $(277) $(2,340) $(3,023)
  Unrealized derivative losses, net Unfunded pension obligations, net Foreign currency translation adjustment, net Available-for-sale securities, net Total
  (in millions)
Balance at the beginning of the period $(307) $(291) $(2,284) —
 $(2,882)
Other comprehensive income (loss) before reclassifications (131) 8
 (218) (1) (342)
Amount reclassified to earnings 52
 7
 (51) —
 8
Other comprehensive income (79) 15
 (269) (1) (334)
Balance sheet reclassification related to an equity method investment (1)
 19
 —
 21
 —
 40
Balance at the end of the period $(367) $(276) $(2,532) $(1) $(3,176)
_____________________________
(1)Reclassification resulting from Silver Ridge transaction.See Note 7 — Investments In and Advances to Affiliates for further information.
Reclassifications out of accumulated other comprehensive lossAOCL for the periods indicated were as follows:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
Details About Accumulated Other Comprehensive Loss Components Affected Line Item in the Condensed Consolidated Statement of Operations 2014 2013 2014 2013
Details About AOCL Components Affected Line Item in the Condensed Consolidated Statement of Operations 2014 2013 2014 2013
 
(in millions) (1)
 
(in millions) (1)
Unrealized derivative losses, netUnrealized derivative losses, net  Unrealized derivative losses, net  
 Non-regulated revenue $6
 $(1) $19
 $(1) Non-regulated revenue $4
 $(3) $23
 $(4)
 Non-regulated cost of sales (3) (1) (2) (2) Non-regulated cost of sales (2) (2) (4) (4)
 Interest expense (31) (34) (63) (69) Interest expense (39) (36) (102) (105)
 Gain on sale of investments —
 (21) —
 (21) Gain on sale of investments —
 —
 —
 (21)
 Foreign currency transaction gains (losses) 7
 (17) 4
 (10) Foreign currency transaction gains (losses) (17) 7
 (13) (3)
 Income from continuing operations before taxes and equity in earnings of affiliates (21) (74) (42) (103) Income from continuing operations before taxes and equity in earnings of affiliates (54) (34) (96) (137)
 Income tax expense 10
 15
 13
 22
 Income tax expense 10
 8
 23
 30
 Net equity in earnings of affiliates (2) (2) (3) (4) Net equity in earnings of affiliates —
 (1) (3) (5)
 Income from continuing operations (13) (61) (32) (85) Income from continuing operations (44) (27) (76) (112)
 Income from continuing operations attributable to noncontrolling interests 15
 11
 15
 13
 Income from continuing operations attributable to noncontrolling interests 9
 2
 24
 15
 Net income (loss) attributable to The AES Corporation $2
 $(50) $(17) $(72) Net income attributable to The AES Corporation $(35) $(25) $(52) $(97)
Amortization of defined benefit pension actuarial loss, netAmortization of defined benefit pension actuarial loss, net  Amortization of defined benefit pension actuarial loss, net  
 Regulated cost of sales $(9) $(19) $(17) $(39) Regulated cost of sales $(8) $(17) $(25) $(56)
 Non-regulated cost of sales 1
 (1) —
 (2) Non-regulated cost of sales —
 (1) —
 (3)
 Income from continuing operations before taxes and equity in earnings of affiliates (8) (20) (17) (41) Other income —
 —
 (2) —
 Income tax expense (2) 7
 1
 14
 Income from continuing operations before taxes and equity in earnings of affiliates (8) (18) (27) (59)
 Other income (2) —
 (2) —
 Income tax expense 3
 6
 4
 20
 Income from continuing operations (12) (13) (18) (27) Income from continuing operations (5) (12) (23) (39)
 Net loss from disposal and impairments of discontinued businesses 2
 —
 2
 —
 Net loss from disposal and impairments of discontinued businesses —
 9
 2
 30
 Net income (10) (13) (16) (27) Net income (5) (3) (21) (9)
 Income from continuing operations attributable to noncontrolling interests 7
 10
 11
 21
 Income from continuing operations attributable to noncontrolling interests 3
 —
 14
 —
 Net income (loss) attributable to The AES Corporation $(3) $(3) $(5) $(6) Net income attributable to The AES Corporation $(2) $(3) $(7) $(9)
Available-for-sale securities, netAvailable-for-sale securities, net  Available-for-sale securities, net  
 Interest income $—
 $(1) $—
 $(1) Interest income $—
 $—
 $—
 $(1)
 Net income attributable to The AES Corporation $—
 $(1) $—
 $(1) Net income attributable to The AES Corporation $—
 $—
 $—
 $(1)
Foreign currency translation adjustment, netForeign currency translation adjustment, net  Foreign currency translation adjustment, net  
 Gain on sale of investments $—
 $(4) $—
 $(1) Gain on sale of investments $4
 $—
 $4
 $(1)
 Net loss from disposal and impairments of discontinued businesses 53
 (35) 47
 (35) Net loss from disposal and impairments of discontinued businesses —
 —
 47
 (35)
 Net income (loss) attributable to The AES Corporation $53
 $(39) $47
 $(36) Net income attributable to The AES Corporation $4
 $—
 $51
 $(36)
Total reclassifications for the period, net of income tax and noncontrolling interestsTotal reclassifications for the period, net of income tax and noncontrolling interests $52
 $(93) $25
 $(115)Total reclassifications for the period, net of income tax and noncontrolling interests $(33) $(28) $(8) $(143)
_____________________________
(1)
19



(1) Amounts in parentheses indicate debits to the condensed consolidated statement of operations.
Amounts in parentheses indicate debits to the condensed consolidated statement of operations.
Stock Repurchase Program
During the three months ended JuneSeptember 30, 2014, the Company repurchased 7,378,387 shares of AES common stock repurchasedat a cost of $108 million under the existing stock repurchase program (the "Program") totaled 2,305,713 at a total cost of $32 million.. The cumulative purchases underrepurchases since the Program commenced in July 2010 has totaled 86,317,94493,696,331 shares at a total cost of $1$1.1 billion, which includes a nominal amount of commissions (average price per share of $11.98,$12.18, including commissions). As of June 30, 2014, $159 million was available under the Program.
The common stock repurchased has been classified as treasury stock and accounted for using the cost method. A total of 91,126,094 and 90,808,168 shares were held as treasury stock at June 30, 2014 and December 31, 2013, respectively. Restricted

18



stock units under the Company’s employee benefit plans are issued from treasury stock. The Company has not retired any shares repurchased under the Program.
The Company's Board of Directors recently authorized a further increase in the Program by an additional $140 million, which increased the total remaining amount for repurchases of AES common stock repurchased since it began the Program in July 2010.from $52 million to $192 million as of September 30, 2014.
Subsequent to JuneSeptember 30, 2014, the Company repurchased an additional 1,065,7002,960,908 shares at a cost of $15.6$42 million, bringing the cumulative repurchases total through August 6,November 5, 2014 to 87,383,64496,657,239 shares at a total cost of $1$1.2 billion (average price of $12.01$12.25 per share including commissions). As of November 5, 2014, $150 million remains available under the Program.
12. SEGMENTS
The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally and is organized by geographic regions which provide better socio-political-economic understanding of our business. The management reporting structure is organized along six strategic business units
(“SBUs”) — led by our Chief Executive Officer (“CEO”). Using the accounting guidance on segment reporting, the Company has determined that it has six reportable segments corresponding to its six SBUs:
US SBU;
Andes SBU;
Brazil SBU;
MCAC SBU;
EMEA SBU; and
Asia SBU
Corporate and Other — Silver Ridge Power (formerly AES Solar Holding Company) and certain otherCertain unconsolidated businesses are accounted for using the equity method of accounting; therefore, their operating results are included in “Net Equity in Earnings of Affiliates” on the face of the Condensed Consolidated Statements of Operations, not in revenue. “Corporate and Other” also includes corporate overhead costs which are not directly associated with the operations of our six reportable segments and other intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.
The Company uses Adjusted PTCPretax Contribution ("Adjusted PTC") as its primary segment performance measure. Adjusted PTC, a non-GAAP measure, is defined by the Company as pretax income from continuing operations attributable to AES excluding unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, gains or losses due to dispositions and acquisitions of business interests, losses due to impairments and costs due to the early retirement of debt. The Company has concluded that Adjusted PTC best reflects the underlying business performance of the Company and is the most relevant measure considered in the Company’s internal evaluation of the financial performance of its segments. Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists the investors in determining which businesses have the greatest impact on the overall Company results.    
Corporate allocations include certain self-insurance activities which are reflected within segment Adjusted PTC. All intra-segment activity has been eliminated with respect to revenue and Adjusted PTC within the segment. Inter-segment activity has been eliminated within the total consolidated results. Asset information for businesses that were discontinued or classified as held-for-sale as of June 30, 2014 is segregated and is shown in the line “Discontinued businesses” in the accompanying segment tables.

20



Information about the Company’s operations by segment for the periods indicated was as follows:
Revenue Total Revenue Intersegment External Revenue Total Revenue Intersegment External Revenue
Three Months Ended June 30,2014 2013 2014 2013 2014 2013
Three Months Ended September 30, 2014 2013 2014 2013 2014 2013
 (in millions)(in millions)
US SBU $893
 $858
 $—
 $—
 $893
 $858
 $1,002
 $966
 $—
 $—
 $1,002
 $966
Andes SBU 724
 725
 (1) —
 723
 725
 704
 629
 (1) (1) 703
 628
Brazil SBU 1,533
 1,230
 —
 —
 1,533
 1,230
 1,548
 1,275
 —
 —
 1,548
 1,275
MCAC SBU 692
 694
 —
 —
 692
 694
 693
 683
 (1) —
 692
 683
EMEA SBU 305
 295
 —
 —
 305
 295
 371
 332
 —
 —
 371
 332
Asia SBU 163
 142
 —
 —
 163
 142
 125
 113
 —
 —
 125
 113
Corporate and Other 5
 3
 (3) (2) 2
 1
 4
 1
 (4) (2) —
 (1)
Total Revenue $4,315
 $3,947
 $(4) $(2) $4,311
 $3,945
 $4,447
 $3,999
 $(6) $(3) $4,441
 $3,996
Revenue Total Revenue Intersegment External Revenue Total Revenue Intersegment External Revenue
Six Months Ended June 30,2014 2013 2014 2013 2014 2013
Nine Months Ended September 30, 2014 2013 2014 2013 2014 2013
 (in millions)(in millions)
US SBU $1,894
 $1,744
 $—
 $—
 $1,894
 $1,744
 $2,896
 $2,710
 $—
 $—
 $2,896
 $2,710
Andes SBU 1,344
 1,415
 (1) —
 1,343
 1,415
 2,048
 2,044
 (2) (1) 2,046
 2,043
Brazil SBU 2,978
 2,659
 —
 —
 2,978
 2,659
 4,526
 3,934
 —
 —
 4,526
 3,934
MCAC SBU 1,330
 1,363
 (1) —
 1,329
 1,363
 2,023
 2,046
 (2) —
 2,021
 2,046
EMEA SBU 696
 638
 —
 —
 696
 638
 1,067
 970
 —
 —
 1,067
 970
Asia SBU 331
 275
 —
 —
 331
 275
 456
 388
 —
 —
 456
 388
Corporate and Other 7
 4
 (5) (3) 2
 1
 11
 5
 (9) (5) 2
 —
Total Revenue $8,580
 $8,098
 $(7) $(3) $8,573
 $8,095
 $13,027
 $12,097
 $(13) $(6) $13,014
 $12,091
  Total Adjusted Pretax Contribution Intersegment External Adjusted Pretax Contribution
Adjusted Pretax Contribution (1)
Three Months Ended September 30,2014 2013 2014 2013 2014 2013
  (in millions)
US SBU $156
 $132
 $3
 $3
 $159
 $135
Andes SBU 120
 109
 (1) 6
 119
 115
Brazil SBU —
 84
 1
 1
 1
 85
MCAC SBU 124
 96
 4
 4
 128
 100
EMEA SBU 79
 66
 3
 3
 82
 69
Asia SBU 2
 30
 —
 1
 2
 31
Corporate and Other (127) (130) (10) (18) (137) (148)
Total Adjusted Pretax Contribution $354
 $387
 $—
 $—
 $354
 $387
Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:    
Unrealized derivative gains (losses) (11) 7
Unrealized foreign currency gains (losses) (62) 21
Disposition/acquisition gains 367
 4
Impairment losses (30) (189)
Loss on extinguishment of debt (66) —
Pretax contribution 552
 230
Add: income from continuing operations before taxes, attributable to noncontrolling interests 48
 235
Less: Net equity in earnings of affiliates (6) 15
Income from continuing operations before taxes and equity in earnings of affiliates $606
 $450

1921



  
Total Adjusted
Pretax Contribution
 Intersegment External Adjusted
Pretax Contribution
Adjusted Pretax Contribution (1)
Three Months Ended June 30,2014 2013 2014 2013 2014 2013
  (in millions)
US SBU $80
 $63
 $3
 $3
 $83
 $66
Andes SBU 104
 88
 1
 4
 105
 92
Brazil SBU 115
 78
 —
 —
 115
 78
MCAC SBU 95
 104
 10
 4
 105
 108
EMEA SBU 73
 72
 3
 2
 76
 74
Asia SBU 23
 40
 —
 —
 23
 40
Corporate and Other (150) (156) (17) (13) (167) (169)
Total Adjusted Pretax Contribution $340
 $289
 $—
 $—
 $340
 $289
Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:    
Unrealized derivative gains (losses) 22
 53
Unrealized foreign currency gains (losses) (7) (23)
Disposition/acquisition gains (losses) (2) 23
Impairment losses (99) —
Loss on extinguishment of debt (13) (164)
Pretax contribution 241
 178
Add: income from continuing operations before taxes, attributable to noncontrolling interests 197
 231
Less: Net equity in earnings of affiliates 20
 2
Income from continuing operations before taxes and equity in earnings of affiliates $418
 $407
 Total Adjusted
Pretax Contribution		 Intersegment External Adjusted
Pretax Contribution		 Total Adjusted Pretax Contribution Intersegment External Adjusted Pretax Contribution
Adjusted Pretax Contribution (1)
Six Months Ended June 30,2014 2013 2014 2013 2014 2013
Nine Months Ended September 30, 2014 2013 2014 2013 2014 2013
 (in millions)(in millions)
US SBU $155
 $196
 $6
 $5
 $161
 $201
$311
 $328
 $9
 $8
 $320
 $336
Andes SBU 157
 169
 4
 7
 161
 176
 277
 278
 3
 13
 280
 291
Brazil SBU 184
 120
 1
 1
 185
 121
 184
 204
 2
 2
 186
 206
MCAC SBU 160
 160
 14
 7
 174
 167
 284
 256
 18
 11
 302
 267
EMEA SBU 188
 168
 6
 5
 194
 173
 267
 234
 9
 8
 276
 242
Asia SBU 31
 71
 1
 1
 32
 72
 33
 101
 1
 2
 34
 103
Corporate and Other (292) (325) (32) (26) (324) (351) (419) (455) (42) (44) (461) (499)
Total Adjusted Pretax Contribution $583
 $559
 $—
 $—
 $583
 $559
 $937
 $946
 $—
 $—
 $937
 $946
Reconciliation to Income from Continuing Operations before Taxes and Equity Earnings of Affiliates:
Non-GAAP Adjustments:Non-GAAP Adjustments:    Non-GAAP Adjustments:    
Unrealized derivative gains (losses) 32
 39
Unrealized foreign currency gains (losses) (33) (49)
Disposition/acquisition gains (losses) (1) 26
Unrealized derivative gainsUnrealized derivative gains 21
 46
Unrealized foreign currency lossesUnrealized foreign currency losses (95) (28)
Disposition/acquisition gainsDisposition/acquisition gains 366
 30
Impairment lossesImpairment losses (265) (48)Impairment losses (295) (237)
Loss on extinguishment of debtLoss on extinguishment of debt (147) (207)Loss on extinguishment of debt (213) (207)
Pretax contributionPretax contribution 169
 320
Pretax contribution 721
 550
Add: income from continuing operations before taxes, attributable to noncontrolling interestsAdd: income from continuing operations before taxes, attributable to noncontrolling interests 412
 403
Add: income from continuing operations before taxes, attributable to noncontrolling interests 460
 638
Less: Net equity in earnings of affiliatesLess: Net equity in earnings of affiliates 45
 6
Less: Net equity in earnings of affiliates 39
 21
Income from continuing operations before taxes and equity in earnings of affiliatesIncome from continuing operations before taxes and equity in earnings of affiliates $536
 $717
Income from continuing operations before taxes and equity in earnings of affiliates $1,142
 $1,167
_____________________________
(1) 
Adjusted pretax contribution in each segment before intersegment eliminations includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees and the write-off of intercompany balances.

20



Assets by segment as of the periods indicated were as follows:
 Total Assets Total Assets
 June 30, 2014 December 31, 2013 September 30, 2014 December 31, 2013
Assets (in millions) (in millions)
US SBU $9,835
 $9,952
 $9,899
 $9,952
Andes SBU 7,458
 7,356
 7,641
 7,356
Brazil SBU 9,144
 8,388
 8,709
 8,388
MCAC SBU 5,060
 5,075
 5,115
 5,075
EMEA SBU 4,240
 4,191
 3,720
 4,191
Asia SBU 2,953
 2,810
 3,075
 2,810
Discontinued businesses —
 1,718
 —
 1,718
Corporate and Other & eliminations 743
 921
 824
 921
Total Assets $39,433
 $40,411
 $38,983
 $40,411
13. OTHER INCOME AND EXPENSE
Other Income
Other income generally includes contract terminations, gains on asset sales and extinguishments of liabilities, favorable judgments on contingencies, and other income from miscellaneous transactions. The components of other income are summarized as follows:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
Contract termination (Beaver Valley) $—
 $—
 $—
 $60
 $—
 $—
 $—
 $60
Contingency reversal (Kazakhstan) (1)

18

—

18

—
Contingency reversal —
 10
 18
(1) 
10
Gain on sale of assets 8
 4
 10
 5
 3
 2
 13
 9
Other 7
 9
 16
 16
 9
 13
 25
 27
Total other income $33
 $13
 $44
 $81
 $12
 $25
 $56
 $106
_____________________________
(1) Reversal of a liability in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.

22



Other Expense
Other expense generally includes losses on asset sales, legal contingencies and losses from other miscellaneous transactions. The components of other expense are summarized as follows:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
Loss on sale and disposal of assets $12
 $10
 $19
 $25
 $12
 $12
 $31
 $36
Contract termination —
 —
 —
 7
 —
 —
 —
 7
Other 5
 7
 6
 11
 —
 3
 6
 15
Total other expense $17
 $17
 $25
 $43
 $12
 $15
 $37
 $58
14. GOODWILL IMPAIRMENT
DPLER — During the first quarter of 2014, the Company performed an interim impairment test on the $136 million in goodwill at its DPLER reporting unit, a competitive retail marketer selling retail electricity to customers in Ohio and Illinois. The DPLER reporting unit was identified as being "at risk" during the fourth quarter of 2013. The impairment indicators arose based on market information available regarding actual and proposed sales of competitive retail marketers, which indicated a significant decline in valuations during the first quarter of 2014.
In Step 1 of the interim impairment test, the fair value of the reporting unit was determined to be less than its carrying amount under both the market approach and the income approach using a discounted cash flow valuation model. The significant assumptions included commodity price curves, estimated electricity to be demanded by its customers, changes in its customer base through attrition and expansion, discount rates, the assumed tax structure and the level of working capital required to run the business. 
In the preliminary Step 2 of the interim impairment test, the goodwill was determined to have an implied fair value of zero after the hypothetical purchase price allocation and the Company accordingly recognized a full impairment of the $136 million in goodwill at the DPLER reporting unit during the three months ended March 31, 2014, which was the Company's best estimate of the impairment loss based on the results of the preliminary Step 2 test. In the second quarter of 2014, the Company finalized the

21



measurement of the goodwill impairment charge that was recorded in the first quarter of 2014, which resulted in no adjustments to the amount recognized.2014. DPLER is reported in the US SBU reportable segment. 
Buffalo Gap — During the first quarter of 2014, the Company recognized an $18 million impairment of its goodwill at its Buffalo Gap reporting unit, which is comprised of three wind projects in Texas with an aggregate generation capacity of 524 MW, and is reported in the US SBU reportable segment.
Ebute—During the third quarter of 2013, the Company performed an interim goodwill impairment test at Ebute, a 294 MW gas-fired plant in Nigeria, and recognized the entire goodwill balance of $58 million as goodwill impairment expense. For further details regarding this impairment, see Note 10 — Goodwill and Other Intangible Assets of the 2013 audited consolidated financial statements included in Item 8 of the Company's 2013 Form 10-K.
15. ASSET IMPAIRMENT EXPENSE
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
Beaver Valley $—
 $—
 $—
 $46
 $—
 $—
 $—
 $46
DP&L (East Bend) —
 —
 12
 —
 —
 —
 12
 —
Ebute 52
 —
 52
 —
 15
 —
 67
 —
Itabo (San Lorenzo) —
 15
 —
 15
UK Wind (Newfield) 11
 —
 11
 —
 —
 —
 11
 —
Other —
 —
 —
 2
 —
 1
 —
 3
Total asset impairment expense $63
 $—
 $75
 $48
 $15
 $16
 $90
 $64
Beaver Valley — In January 2013, Beaver Valley, a wholly-owned 125 MW coal-fired plant in Pennsylvania, entered into an agreement to early terminate its PPA with the offtaker in exchange for a lump-sum payment of $60 million which was received on January 9, 2013. The termination was effective January 8, 2013. Beaver Valley also terminated its fuel supply agreement. Under the PPA termination agreement, annual capacity agreements between the offtaker and PJM Interconnection, LLC (“PJM”) (a regional transmission organization) for 2013 - 2016 have been assigned to Beaver Valley. The termination of the PPA resulted in a significant reduction in the future cash flows of the asset group and was considered an impairment indicator. The carrying amount of the asset group was not recoverable. The carrying amount of the asset group exceeded the fair value of the asset group, resulting in an asset impairment expense of $46 million. Beaver Valley is reported in the US SBU reportable segment.2014
DP&L (East Bend) — During the first quarter of 2014, the Company tested the recoverability of long-lived assets at East Bend, a 186 MW coal-fired plant in Ohio jointly owned by DP&L (a wholly owned subsidiary of AES). Indications during that quarter that the fair value of the asset group was less than its carrying amount were determined to be impairment indicators given how narrowly these long-lived assets had passed the recoverability test during the fourth quarter of 2013. During the first quarter of 2014, the Company determined that the carrying amount of the asset group was not recoverable. The East Bend asset group was determined to have a fair value of $2 million using the market approach. As a result, the Company recognized an asset impairment expense of $12 million. East Bend is reported in the US SBU reportable segment.
Ebute — During the second quarter of 2014, the Company identified impairment indicators at Ebute in Nigeria, resulting from the continued lack of gas supply and the increased likelihood of selling the asset group before the end of its useful life.

23



The Company determined that the carrying amount of the asset group was not recoverable. The Ebute asset group was determined to have a fair value of $47 million using primarily the market approach based on indications about the proceeds that could be received from a future sale, the amount of cash flows estimated to be received until that sale under its power purchase agreement and the amount of cash on hand. As a result, the Company recognized an asset impairment expense of $52 million.
During the third quarter of 2014, the Company identified an additional impairment indicator resulting from lower indications about the potential proceeds that could be received from a future sale and a decline in expected cash flows remaining to be received until that sale. The Company determined that the carrying amount of the asset group was not recoverable. The Ebute asset group was determined to have a fair value of $36 million; as a result, the Company recognized an additional asset impairment expense of $15 million. Ebute is reported in the EMEA SBU reportable segment.
UK Wind (Newfield) — During the second quarter of 2014, the Company tested the recoverability of long-lived assets at its Newfield wind development project in the United Kingdom after the UK government refused to grant a permit necessary for the project to continue. The Company determined that the carrying amount of the asset group was not recoverable. The Newfield asset group was determined to have no fair value using the income approach. As a result, the Company recognized an asset impairment expense of $11 million. UK Wind (Newfield) is reported in the EMEA SBU reportable segment.
2013
Itabo (San Lorenzo)—During the third quarter of 2013, the Company tested the recoverability of long-lived assets at San Lorenzo, a 35 MW LNG fueled plant of Itabo. Itabo was informed by Super-Intendencia de Electricidad (“SIE”), the system regulator in the Dominican Republic, that it would not receive capacity revenue going forward. This communication in combination with current adverse market conditions were determined to be an impairment indicator. The Company performed a long-lived asset impairment test considering different scenarios and determined that, based on undiscounted cash flows, the carrying amount of San Lorenzo was not recoverable. The fair value of San Lorenzo was determined using the market approach based on a broker quote and it was determined that its carrying amount of $22 million exceeded the estimated fair value of $7 million. As a result, the Company recognized an asset impairment expense of $15 million. Itabo is reported in the MCAC SBU reportable segment.
Beaver Valley — In January 2013, Beaver Valley, a wholly-owned 125 MW coal-fired plant in Pennsylvania, entered into an agreement to early terminate its PPA with the offtaker in exchange for a lump-sum payment of $60 million which was received on January 9, 2013. The termination was effective January 8, 2013. Beaver Valley also terminated its fuel supply agreement. Under the PPA termination agreement, annual capacity agreements between the offtaker and PJM Interconnection, LLC (“PJM”) (a regional transmission organization) for 2013 - 2016 have been assigned to Beaver Valley. The termination of the PPA resulted in a significant reduction in the future cash flows of the asset group and was considered an impairment indicator. The carrying amount of the asset group was not recoverable. The carrying amount of the asset group exceeded the fair value of the asset group, resulting in an asset impairment expense of $46 million. Beaver Valley is reported in the US SBU reportable segment.
16. OTHER NON-OPERATING EXPENSE
  Three Months Ended 
 June 30,		 Six Months Ended 
 June 30,
  2014 2013 2014 2013
  (in millions)
Silver Ridge Power $44
 $—
 $44
 $—
Total other non-operating expense $44
 $—
 $44
 $—

Silver Ridge —On June 16, 2014, the Company executed an agreement to sell its 50% ownership interest in Silver Ridge Power, LLC (“SRP”) for a purchase price of $165 million, subject to certain purchase price adjustments, and excluding the Company’s indirect ownership interests in SRP’s solar generation businesses in Italy, Puerto Rico and Spain. SRP is a solar power joint venture of AES and Riverstone Holdings LLC with each partner having a 50% ownership interest in SRP. As a

22



result of the Company's continuing interests and involvement in SRP's solar generation businesses in Italy, Puerto Rico, and Spain, the transaction will not result in a sale for accounting purposes until all continuing involvement by AES has been eliminated. The buyer also has an option to purchase the Company's indirect 50% interest in the Italy solar generation business for additional consideration of $42 million by August 2015.
During the second quarter of 2014, the Company determined that there was a decline in the fair value of its equity method investment in SRP that was other than temporary based on indications about the fair value of the projects in Italy and Spain that resulted from actual and proposed changes to their tariffs. As a result,For the nine months ended September 30, 2014, the Company has recognized a pretax impairment loss of $44$42 million in other non-operating expense in the second quarter of 2014.expense. The sale of thetransaction related to our 50% ownership interest in SRP closed on July 2, 2014 for $179 million. See Note 7 — Investments in and Advances to Affiliates, of this Form 10-Q for further information.
Entek — In September 2014, the Company executed an agreement, subject to the approval of the Company’s Board of Directors, to sell its 49.62% equity interest in AES Entek for $125 million. AES Entek consists of 364 MW of natural gas and hydroelectric generation facilities, plus a coal-fired development project. During the third quarter of 2014, the Company determined there was an other-than-temporary decline in the fair value of its equity method investment in AES Entek and recognized a pretax impairment loss of $18 million including purchase price adjustments.in other non-operating expense. As of September 30, 2014, the Company’s Board of Directors had not approved the sale and, accordingly, the impairment recognized during the third quarter excluded the cumulative translation adjustment (“CTA”) related to AES Entek of $68 million.
In October 2014, the Company’s Board of Directors approved the sale of AES Entek. This will result in the recognition of additional impairment expense related to the CTA in the fourth quarter of 2014. The sale is expected to close during the first quarter of 2015 and is subject to customary regulatory approvals.
17. INCOME TAXES
Chilean Tax Reform —On September 29, 2014, the Chilean government enacted comprehensive tax reforms which introduced significant changes to corporate income tax rates, a modification of the shareholder level tax beginning in 2017, and new “green” taxes primarily over CO2 emissions beginning in 2017. Specifically, two systems of income tax were introduced:

24



Attributed Profit System (“APS”) and Partially Integrated System (“PIS”). The Company expects to elect the APS system which taxes shareholders on an accrued profits basis. Under PIS, shareholders would be taxed on a cash basis.
The corporate income tax rate was raised from 20% to 21% retroactive to January 1, 2014, and under APS is scheduled to increase in steps up to 25% for 2017 and beyond. Under PIS, the maximum rate is 27% and is effective for 2018 and beyond. The impact of remeasuring deferred taxes to account for the enacted change in future applicable income tax rates was recognized as discrete tax expense this quarter and resulted in consolidated income tax expense of $46 million. The impacts of the shareholder level taxes and green taxes will be recognized in future periods and could be material.
During the third quarter of 2014, there was a change in tax status at one of the Company’s businesses in the Dominican Republic. This change resulted in a net $23 million income tax benefit due to the associated elimination of a deferred tax liability no longer required to be recorded. This benefit was recorded as a discrete item in the current quarter.
18. DISCONTINUED OPERATIONS AND HELD-FOR-SALE BUSINESSES
As discussed in Note 1 — Financial Statement Presentation, effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08. The following table summarizes the revenue, income from operations, income tax expense, impairment and loss on disposal of all discontinued operations prior to the adoption of the new accounting guidance for discontinued operations for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 
2013 (1)
 2014 2013
  (in millions)
Revenue $104
 $164
 $233
 $426
Income from operations of discontinued businesses, before income tax $15
 $4
 $49
 $6
Income tax expense (8) (7) (22) (5)
Income (loss) from operations of discontinued businesses, after income tax $7
 $(3) $27
 $1
Net (loss) income from disposal and impairments of discontinued businesses, after income tax $(13) $3
 $(56) $(33)
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 2014 
2013 (1)
  (in millions)
Revenue $—
 $130
 $233
 $556
Income (loss) from operations of discontinued businesses, before income tax $—
 $(41) $49
 $(35)
Income tax benefit (expense) —
 3
 (22) (2)
Income (loss) from operations of discontinued businesses, after income tax $—
 $(38) $27
 $(37)
Net loss from disposal and impairments of discontinued businesses, after income tax $—
 $(78) $(56) $(111)
_____________________________
(1) Includes the results of operations of our Ukraine utility businesses, which were sold in April 2013.
Cameroon—In September 2013, a subsidiary of the Company executed sale agreements for the sale of AES White Cliffs B.V. (owner of 56% of AES SONEL S.A), AES Kribi Holdings B.V. (owner of 56% of Kribi Power Development Company S.A.) and AES Dibamba Holdings B.V., (owner of 56% of Dibamba Power Development Company S.A.). In June 2014, the Company sold its entire equity interest in all three businesses in Cameroon. Net proceeds from the sale transaction were $202 million with $162 million received at closing and non-contingent consideration of $40 million to be received in June 2016. The carrying amount of $40 million, which approximates fair value, is classified in other noncurrent assets and is secured by a $40 million letter of credit from a well-capitalized, multinational bank. Between meeting the held-for-sale criteria in September 2013 through the first quarter of 2014, the Company has recognized impairments of $101 million representing the difference between their aggregate carrying amount of $435 million and fair value less costs to sell of $334 million. During the second quarter of 2014, the Company recognized an additional loss on sale of $7 million. These businesses were previously reported in EMEA SBU reportable segment and "Corporate and Other".segment.
Saurashtra—In October 2013, the Company executed a sale agreement for the sale of its wholly owned subsidiary AES Saurashtra Private Ltd, a 39 MW wind project in India. The sale transaction closed on February 24, 2014 and net proceeds of $8 million were received. Saurashtra was previously reported in the Asia SBU reportable segment.
U.S. wind projects—In November 2013, the Company executed an agreement for the sale of its 100% membership interests in three wind projects with an aggregate generation capacity of 234 MW: Condon in California, Lake Benton I in Minnesota and Storm Lake II in Iowa. Under the terms of the sale agreement, the buyer has an option to purchase the Company's 100% interest in Armenia Mountain, a 101 MW wind project in Pennsylvania at a fixed price of $75 million. The option is exercisable between January 1, 2015 and April 1, 2015 (both dates inclusive). The sale transaction closed on January 30, 2014 and net proceeds of $27 million were received. Approximately $3 million of the net proceeds received have been deferred and allocated to the buyer's option to purchase Armenia Mountain. These wind projects were previously reported in the US SBU reportable segment. Armenia Mountain has not met the held-for-sale criteria and, accordingly, is reflected within continuing operations.
19. DISPOSITIONS
U.K. wind projects — On August 22, 2014, the Company sold 100% of its interests in four operating wind projects located in the U.K. with an aggregate generation capacity of 88 MW. Net proceeds from the sale transaction were $161 million and the Company recognized a pretax gain on sale of $78 million during the third quarter of 2014. These wind projects are reported in the EMEA SBU reportable segment. These wind projects do not meet the criteria to be reported as discontinued operations under ASU

2325



18. DISPOSITIONS2014-8 and, accordingly, the results are reflected within continuing operations. Excluding the gain on sale, the pretax loss for these disposed projects was $19 million and $18 million, respectively, for the three and nine months ended September 30, 2014, and $3 million and $2 million, respectively, for the three and nine months ended September 30, 2013.
Cartagena — On April 26, 2013, the Company sold its remaining interest in AES Energia Cartagena S.R.L. (“AES Cartagena”), a 1,199 MW gas-fired generation business in Spain upon the exercise of a purchase option included in the 2012 sale agreement where the Company sold its majority interest in the business. Net proceeds from the exercise of the option were approximately $24 million and the Company recognized a pretax gain of $20 million during the second quarter of 2013. In 2012, the Company had sold 80% of its 70.81% equity interest in Cartagena and had recognized a pretax gain of $178 million. Under the terms of the 2012 sale agreement, the buyer was granted an option to purchase the Company’s remaining 20% interest during a five-month period beginning March 2013, which was exercised on April 26, 2013 as described above. Due to the Company’s continued ownership interest, which extended beyond one year from the completion of the sale of its 80% interest in February 2012, the prior-period operating results of AES Cartagena were not reclassified as discontinued operations.
19.20. EARNINGS PER SHARE
Basic and diluted earnings per share are based on the weighted-average number of shares of common stock and potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted earnings per share, includes the effects of dilutive restricted stock units, stock options and convertible securities. The effect of such potential common stock is computed using the treasury stock method or the if-converted method, as applicable. The following tables present a reconciliation of the numerator and denominator of the basic and diluted earnings per share computation for income from continuing operations for the periods indicated. In the table below, income represents the numerator and weighted-average shares represent the denominator:
 Three Months Ended June 30, Three Months Ended September 30,
 2014 2013 2014 2013
 Income Shares $ per Share Income Shares $ per Share Income Shares $ per Share Income Shares $ per Share
 (in millions except per share data) (in millions except per share data)
BASIC EARNINGS PER SHARE                        
Income from continuing operations attributable to The AES Corporation common stockholders $142
 725
 $0.20
 $167
 747
 $0.22
 $488
 721
 $0.68
 $175
 742
 $0.23
EFFECT OF DILUTIVE SECURITIES     
           
      
Convertible securities 6
 15
 (0.01) —
 —
 —
Stock options —
 1
 —
 —
 —
 —
 —
 1
 —
 —
 1
 —
Restricted stock units —
 2
 —
 —
 4
 —
 —
 3
 —
 —
 4
 —
DILUTED EARNINGS PER SHARE $142
 728
 $0.20
 $167
 751
 $0.22
 $494
 740
 $0.67
 $175
 747
 $0.23
 Six Months Ended June 30, Nine Months Ended September 30,
 2014 2013 2014 2013
 Income Shares $ per Share Income Shares $ per Share Income Shares $ per Share Income Shares $ per Share
 (in millions except per share data) (in millions except per share data)
BASIC EARNINGS PER SHARE                        
Income from continuing operations attributable to The AES Corporation common stockholders $95
 725
 $0.13
 $279
 746
 $0.37
 $583
 724
 $0.81
 $454
 745
 $0.61
EFFECT OF DILUTIVE SECURITIES                        
Stock options —
 1
 —
 —
 1
 —
 —
 —
 —
 —
 —
 —
Restricted stock units —
 2
 —
 —
 3
 —
 —
 3
 —
 —
 4
 —
DILUTED EARNINGS PER SHARE $95
 728
 $0.13
 $279
 750
 $0.37
 $583
 727
 $0.81
 $454
 749
 $0.61
The calculation of diluted earnings per share excluded 5 million and 76 million options outstanding at JuneSeptember 30, 2014 and 2013, respectively, that could potentially dilute basic earnings per share in the future. These options were not included in the computation of diluted earnings per share because the exercise price of these options exceeded the average market price during the related period.
The calculation of diluted earnings per share also excluded 21 million and 1 million restricted stock units outstanding at JuneSeptember 30, 2014 and 2013, respectively, that could potentially dilute basic earnings per share in the future. These restricted stock units were not included in the computation of diluted earnings per share because the average amount of compensation cost per share attributed to future service and not yet recognized exceeded the average market price during the related period and thus to include the restricted units would have been anti-dilutive.
For the three and six months ended JuneSeptember 30, 2014, all convertible debentures were included in the earnings per share calculation. For the three months ended September 30, 2013, all 15 million shares of potential common stock associated with convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive. For the nine

26



months ended September 30, 2014 and 2013, all 15 million shares of potential common stock associated with convertible debentures were omitted from the earnings per share calculation because they were anti-dilutive.
During the sixnine months ended JuneSeptember 30, 2014, 1 million shares of common stock were issued under the Company’s profit-sharing plan.

24



20.21. SUBSEQUENT EVENTS
AES Entek sale — In October 2014, the Company entered into an agreement to sell its 49.62% equity interest in AES Entek for $125 million. See Note 16 — Other Non-Operating Expense for further information.
Dividends — On October 10, 2014, the Company's Board of Directors declared a dividend of $0.05 per outstanding common share payable on November 17, 2014 to the shareholders of record at the close of business on November 3, 2014.
Stock Repurchase Program — The Company continued stock repurchases after JuneSeptember 30, 2014 under its stock repurchase program. For additional information on stock repurchases after the quarter, see Note 11— Equity.
Dividends —On July 15, 2014 the Company's Board of Directors declared a dividend of $0.05 per outstanding common share payable on August 15, 2014 to the shareholders of record at the close of business on August 1, 2014.
Masinloc Sale — The sale of a noncontrolling interest in Masinloc closed on July 15, 2014. See Note 11 — Equity for further information.
Silver Ridge Sale — The sale of the Company's ownership in Silver Ridge Power closed on July 2, 2014. See Note 16 — Other Non-Operating Expense for further information.
Recourse Debt Transaction - On July 25, 2014 the Company issued two notices to call $320 million aggregate principal amount of unsecured notes. See Note 8 — Debt for further information.Equity.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
In this Quarterly Report on Form 10-Q (“Form 10-Q”), the terms “AES,” “the Company,” “us,” or “we” refer to the consolidated entity and all of its subsidiaries and affiliates, collectively. The term “The AES Corporation” or “the Parent Company” refers only to the parent, publicly held holding company, The AES Corporation, excluding its subsidiaries and affiliates. The condensed consolidated financial statements included in Item 1. — Financial Statements of this Form 10-Q and the discussions contained herein should be read in conjunction with our 2013 Form 10-K.
FORWARD-LOOKING INFORMATION
The following discussion may contain forward-looking statements regarding us, our business, prospects and our results of operations that are subject to certain risks and uncertainties posed by many factors and events that could cause our actual business, prospects and results of operations to differ materially from those that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those described in Item 1A. — Risk Factors and Item 7:7. — Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2013 Form 10-K and subsequent filings with the SEC. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We undertake no obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the SEC that advise of the risks and factors that may affect our business.
Overview of Our Business
We are a diversified power generation and utility company organized into six market-oriented Strategic Business Units (“SBUs”):SBUs: US (United States), Andes (Chile, Colombia, and Argentina), Brazil, MCAC (Mexico, Central America and the Caribbean), EMEA (Europe, Middle East and Africa), and Asia. For additional information regarding our business, see Item 1. —Business of our 2013 Form 10-K.
Our Organization — The segment reporting structure uses the Company’s management reporting structure as its foundation to reflect how the Company manages the business internally and is organized by geographic regions which provide better socio-political-economic understanding of our business. The management reporting structure is organized along six SBUs — led by our Chief Executive Officer (“CEO”).CEO. Using the accounting guidance on segment reporting, the Company has determined that its reportable segments correspond to the six SBUs. Management’s discussion and analysis of Operating Margin, Adjusted Operating Margin and Adjusted Pretax Contribution is organized according to the SBU structure as follows:
US SBU
Andes SBU
Brazil SBU
MCAC SBU
EMEA SBU
Asia SBU
Corporate and Other — The Company’s corporate operations are reported within “Corporate and Other” because they do not require separate disclosure under segment reporting accounting guidance.

2527



Key Topics in the ManagementManagement's Discussion and Analysis
Our discussion covers the following:
Overview of Q2Q3 2014 Results, Management's Strategic Priorities and Strategic Performance
Review of Consolidated Results of Operations
SBU Analysis and Non-GAAP Measures
Key Trends and Uncertainties
Capital Resources and Liquidity

Q23 2014 Performance
Earnings Per Share Results in Q23 2014
Three Months Ended June 30, Six Months Ended June 30,Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 Change % Change 2014 2013 Change % Change2014 2013 Change % Change 2014 2013 Change % Change
Diluted earnings per share from continuing operations$0.20
 $0.22
 $(0.02) (9)% $0.13
 $0.37
 $(0.24) (65)%$0.67
 $0.23
 $0.44
 191 % $0.81
 $0.61
 $0.20
 33 %
Adjusted earnings per share (a non-GAAP measure)(1)
$0.28
 $0.35
 $(0.07) (20)% $0.53
 $0.62
 $(0.09) (15)%$0.37
 $0.39
 $(0.02) (5)% $0.89
 $1.01
 $(0.12) (12)%
_____________________________
(1)
See reconciliation and definition under Non-GAAP Measures.    
Three Months Ended JuneSeptember 30, 2014
Diluted earnings per share from continuing operations decreased $0.02,increased $0.44, or 9%191%, to $0.20$0.67 principally due to the gain on sale of a higher effective tax rate, higher assetnoncontrolling interest in Masinloc, the gain on sale of UK wind assets, lower goodwill impairment expense, and lower gross margin, and other non-operating expense, in 2014 resulting from the other-than-temporary impairment of Silver Ridge Power, partially offset by decreased losseslower operating margin, higher foreign currency transaction loss, higher loss on extinguishment of debt.debt, and higher interest expense.
Adjusted earnings per share, a non-GAAP measure, decreased by 20%5% primarily due to a higher effective tax rate and lower grossoperating margin.
SixNine Months Ended JuneSeptember 30, 2014
Diluted earnings per share from continuing operations decreased $0.24,increased $0.20, or 65%33%, to $0.13$0.81 principally due to the gain on sale of a noncontrolling interest in Masinloc, the gain on sale of UK wind assets, and lower other non-operating expense, partially offset by goodwill impairments in the US, alower operating margin, higher effective tax rate, lower gross margin, other non-operating expense in 2014 resulting from the other-than-temporary impairment of Silver Ridge Power, and higher other income in 2013 resulting from the termination of the PPA at Beaver Valley, partially offset by decreased losses on extinguishment of debt and lower foreign currency transaction losses in 2014.
Adjusted earnings per share, a non-GAAP measure, decreased by 15% primarily due to a higher effective tax rate, lower gross margin,loss, and higher other income in 2013 resulting from the termination of the PPA at Beaver Valley.
Adjusted earnings per share, a non-GAAP measure, decreased by 12% primarily due to an increased tax impact, lower operating margin, and higher other income in 2013 resulting from the PPA termination at Beaver Valley, partially offset by lower Parent interest expense, the reversal of a loss contingency at Sul, and lower share count.
Management’s Strategic Priorities
Management is focused on the following priorities:

Management of our portfolio of Generation and Utility businesses to create value for our stakeholders, including customers and shareholders, through safe, reliable, and sustainable operations and effective cost management;
Driving our business to manage capital more effectively and to increase the amount of discretionary cash available for deployment into debt repayment, growth investments, shareholder dividends and share buybacks;
Growing our business through disciplined and targeted initiatives, with a focus on platform expansions, adjacent services and selective acquisitions, as well as improving the risk-adjusted returns on our existing assets. To this end, we may reduce our exposure to or opportunistically exit markets in which we do not foresee sufficient growth opportunities or where we are unable to earn a fair risk-adjusted return relative to monetization alternatives; and
Reduce the cash flow and earnings volatility of our businesses by proactively managing our currency, commodity and political risk exposures, mostly through contractual and regulatory mechanisms, as well as commercial hedging activities. We also will continue to limit our risk by utilizing non-recourse project financing for the majority of our businesses.
Q2Q3 2014 Strategic Performance
We continue to execute on our strategic objectives of safe, reliable and sustainable operations, improvement of available capital and deployment of discretionary cash and realignment of our geographic focus. Key highlights of our progress during the sixnine months ended JuneSeptember 30, 2014 include:

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Safe, Reliable and Sustainable Operations
Our Key Performance Indicators ("KPIs") for the periods indicated are as follows:
 For the Six Months Ended June 30, For the Nine Months Ended September 30,
Key Performance Indicators 2014 2013 Variance 2014 2013 Variance
Safety: Employee Lost-Time Incident Case Rate .090
 .103
 13 % 0.1
 0.103
 3 %
Safety: Operational Contractor Lost-Time Incident Case Rate .012
 .040
 70 % 0.093
 0.137
 32 %
Generation            
Commercial Availability (%) 91.3% 93.2% (1.9)% 91.2% 93.6% (2.4)%
Equivalent Forced Outage Factor (EFOF, %) 3.9% 2.7% (1.2)% 3.5% 2.8% (0.7)%
Heat Rate (BTU/kWh) 9,796
 9,600
 (196) 9,828
 9,650
 (178)
Utility            
System Average Interruption Duration Index (SAIDI, hours) 5.8
 6.6
 0.8
 5.5
 6.1
 0.6
System Average Interruption Frequency Index (SAIFI, number of interruptions) 3.7
 3.3
 (0.4) 3.6
 3.0
 (0.6)
Non-Technical Losses (%) 2.0% 2.5% 0.5 % 2.1% 2.4% 0.3 %

Definitions:
Lost-Time Incident Case Rate: Number of lost-time cases per number of full-time employees or contractors.
Commercial Availability: Actual variable margin, as a percentage of potential variable margin if the unit had been available at full capacity during outages.
Equivalent Forced Outage Factor:Factor ("EFOF"): The percentage of the time that a plant is not capable of producing energy, due to unplanned operational reductions in production.
Heat Rate: The amount of energy used by an electrical generator or power plant to generate one kilowatt-hour (kWh).
System Average Interruption Duration Index:Index ("SAIDI"): The total hours of interruption the average customer experiences annually. Trailing 12-month average.
System Average Interruption Frequency Index: The average number of interruptions the average customer experiences annually. Trailing 12-month average.
Non-Technical Losses: Delivered energy that was not billed due to measurement error, theft or other reasons. Trailing 12-month average.
We continue to focus on safety as our top priority. Our safety performance improved in the secondthird quarter of 2014, as we lowered our lost-time incident case rates for both employees and operational contractors.
Generation in gigawatt-hours (GWh) is down 3%4% compared to the first sixnine months of 2013, mainly driven by dry hydrological conditions in Brazil and Panama, as well as higher unplanned outages at our generation plants in Ohio and the Philippines. The dry conditions were partially offset by new capacity in Chile.
Compared to the first halfnine months of 2013, our performance on our KPIs was mixed, as our generation KPIs declined while indicators for our utilities improved. Our Commercial Availability and Equivalent Forced Outage Factor (EFOF)EFOF performance deteriorated, largely driven by our unplanned outages at our generation plants in Ohio and the Philippines as discussed above. Most of these events have been resolved and mitigation plans have been implemented. For utilities, our performance on System Average Interruption Duration Index ("SAIDI")SAIDI and Non-Technical Losses improved compared to the first sixnine months of 2013.
Improving Available Capital and Deployment of Discretionary Cash
We continue to focus on improving cash generation and optimizing the use of our parent discretionary cash. During the secondthird quarter of 2014, we generated $232763 million of cash flow from operating activities and closed the sale of our business in Cameroon for $162 million.activities. We utilized cash consistent with our strategy, as we paid a quarterly dividend of $36 million ($0.05 per share), repurchased common stock under the existing stock repurchase program at a total cost of $32$108 million, invested $228 million in our subsidiaries for platform expansions and other purposes, and utilized $31$356 million to reduce and refinance recourse debt at the Parent Company.
Realigning Our Geographic Focus
In the second quarter of 2014, we commenced construction of platform expansion projects in the United States and Chile. We are building 671 MW of new gas-fired capacity at Indianapolis Power & Light and 21 MW of solar capacity at AES Gener. We also continued to advance our pipeline of approximately 4,500 MW of new capacity under construction, including the 531 MW Alto Maipo hydroelectric project in Chile. These projects are scheduled to come on-line through 2018.
We made several announcements regarding asset sales and partnershipsadvancements in our strategy during the quarter. We closed the sale of our interests in our Cameroon assets and exited the country, further reducing our footprint. We also announced two new transactions representing equity proceeds to AES of up to $660 million. In June 2014, we announced the sale of the majority100% of our solarinterest in our Turkish assets in Europe, India and upon closing will exit that country. We also advanced on two partnership transactions including the United States. In addition, we soldsale of 45% of our interest in the Masinloc facility for $443 million and agreed with our partner to use Masinloc as our exclusive vehicle for growth in the Philippines. Additionally, we executed an agreement to sell an 8% noncontrolling interest in our businesses in the Dominican Republic for $96 million.

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Review of Consolidated Results of Operations
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
Results of operations 2014 2013 $ change % change 2014 2013 $ change % change 2014 2013 $ change % change 2014 2013 $ change % change
 ($ in millions, except per share amounts) ($ in millions, except per share amounts)
Revenue:                    
US SBU $893
 $858
 $35
 4 % $1,894
 $1,744
 $150
 9 % $1,002
 $966
 $36
 4 % $2,896
 $2,710
 $186
 7 %
Andes SBU 724
 725
 (1) — % 1,344
 1,415
 (71) -5 % 704
 629
 75
 12 % 2,048
 2,044
 4
 — %
Brazil SBU 1,533
 1,230
 303
 25 % 2,978
 2,659
 319
 12 % 1,548
 1,275
 273
 21 % 4,526
 3,934
 592
 15 %
MCAC SBU 692
 694
 (2) — % 1,330
 1,363
 (33) -2 % 693
 683
 10
 1 % 2,023
 2,046
 (23) -1 %
EMEA SBU 305
 295
 10
 3 % 696
 638
 58
 9 % 371
 332
 39
 12 % 1,067
 970
 97
 10 %
Asia SBU 163
 142
 21
 15 % 331
 275
 56
 20 % 125
 113
 12
 11 % 456
 388
 68
 18 %
Corporate and Other 5
 3
 2
 67 % 7
 4
 3
 75 % 4
 1
 3
 300 % 11
 5
 6
 120 %
Intersegment eliminations (4) (2) (2) -100 % (7) (3) (4) -133 % (6) (3) (3) -100 % (13) (6) (7) -117 %
Total Revenue 4,311
 3,945
 366
 9 % 8,573
 8,095
 478
 6 % 4,441
 3,996
 445
 11 % 13,014
 12,091
 923
 8 %
Operating Margin:                                
US SBU $144
 $147
 $(3) -2 % $278
 $292
 $(14) -5 % $222
 $206
 $16
 8 % $500
 $498
 $2
 — %
Andes SBU 148
 148
 —
 — % 239
 282
 (43) -15 % 212
 134
 78
 58 % 451
 416
 35
 8 %
Brazil SBU 270
 313
 (43) -14 % 591
 516
 75
 15 % 44
 306
 (262) -86 % 635
 822
 (187) -23 %
MCAC SBU 146
 149
 (3) -2 % 235
 254
 (19) -7 % 176
 143
 33
 23 % 411
 397
 14
 4 %
EMEA SBU 77
 86
 (9) -10 % 210
 200
 10
 5 % 94
 85
 9
 11 % 304
 285
 19
 7 %
Asia SBU 27
 45
 (18) -40 % 37
 83
 (46) -55 % 12
 38
 (26) -68 % 49
 121
 (72) -60 %
Corporate and Other 4
 22
 (18) -82 % 26
 19
 7
 37 % 16
 2
 14
 700 % 42
 21
 21
 100 %
Intersegment eliminations 3
 (9) 12
 133 % (3) 4
 (7) -175 % (9) 13
 (22) -169 % (12) 17
 (29) -171 %
Total Operating Margin 819
 901
 (82) -9 % 1,613
 1,650
 (37) -2 % 767
 927
 (160) -17 % 2,380
 2,577
 (197) -8 %
General and administrative expenses (52) (53) 1
 2 % (103) (107) 4
 4 % (45) (53) 8
 15 % (148) (160) 12
 8 %
Interest expense (323) (337) 14
 4 % (696) (707) 11
 2 % (390) (358) (32) -9 % (1,086) (1,065) (21) -2 %
Interest income 73
 63
 10
 16 % 136
 128
 8
 6 % 69
 85
 (16) -19 % 205
 213
 (8) -4 %
Loss on extinguishment of debt (15) (165) 150
 91 % (149) (212) 63
 30 % (47) —
 (47) NM
 (196) (212) 16
 8 %
Other expense (17) (17) —
 — % (25) (43) 18
 42 % (12) (15) 3
 20 % (37) (58) 21
 36 %
Other income 33
 13
 20
 154 % 44
 81
 (37) -46 % 12
 25
 (13) -52 % 56
 106
 (50) -47 %
Gain on sale of investments —
 20
 (20) -100 % 1
 23
 (22) -96 %
Gain on disposals and sale of investments 362
 3
 359
 NM
 363
 26
 337
 NM
Goodwill impairment expense —
 —
 —
 — % (154) —
 (154) NA
 —
 (58) 58
 100 % (154) (58) (96) -166 %
Asset impairment expense (63) —
 (63) NA
 (75) (48) (27) -56 % (15) (16) 1
 6 % (90) (64) (26) -41 %
Foreign currency transaction gains (losses) 7
 (18) 25
 139 % (12) (48) 36
 75 % (79) 32
 (111) -347 % (91) (16) (75) -469 %
Other non-operating expense (44) —
 (44) NA
 (44) —
 (44) NA
 (16) (122) 106
 87 % (60) (122) 62
 51 %
Income tax expense (157) (76) (81) -107 % (211) (159) (52) -33 % (92) (126) 34
 27 % (303) (285) (18) -6 %
Net equity in earnings of affiliates 20
 2
 18
 900 % 45
 6
 39
 650 % (6) 15
 (21) -140 % 39
 21
 18
 86 %
INCOME FROM CONTINUING OPERATIONS 281
 333
 (52) -16 % 370
 564
 (194) -34 % 508
 339
 169
 50 % 878
 903
 (25) -3 %
Income (loss) from operations of discontinued businesses, net of income tax expense of $8, $7, $22, and $5, respectively 7
 (3) 10
 333 % 27
 1
 26
 NM
Net (loss) gain from disposal and impairments of discontinued businesses, net of income tax (benefit) expense of $5, $0, $4, and $(1), respectively (13) 3
 (16) -533 % (56) (33) (23) -70 %
Income (loss) from operations of discontinued businesses, net of income tax expense (benefit) of $0, $(3), $22, and $2, respectively —
 (38) 38
 100 % 27
 (37) 64
 173 %
Net loss from disposal and impairments of discontinued businesses, net of income tax expense (benefit) of $0, $(1), $4, and $(2), respectively —
 (78) 78
 100 % (56) (111) 55
 50 %
NET INCOME 275
 333
 (58) -17 % 341
 532
 (191) -36 % 508
 223
 285
 128 % 849
 755
 94
 12 %
Noncontrolling interests:                                
Less: Income from continuing operations attributable to noncontrolling interests (139) (166) 27
 16 % (275) (285) 10
 4 % (20) (164) 144
 88 % (295) (449) 154
 34 %
Less: (Income) loss from discontinued operations attributable to noncontrolling interests (3) —
 (3) NA
 9
 2
 7
 350 %
Less: Loss from discontinued operations attributable to noncontrolling interests —
 12
 (12) -100 % 9
 14
 (5) -36 %
NET INCOME ATTRIBUTABLE TO THE AES CORPORATION $133
 $167
 $(34) -20 % $75
 $249
 $(174) -70 % $488
 $71
 $417
 587 % $563
 $320
 $243
 76 %
AMOUNTS ATTRIBUTABLE TO THE AES CORPORATION COMMON STOCKHOLDERS:                                
Income from continuing operations, net of tax $142
 $167
 $(25) -15 % $95
 $279
 $(184) -66 % $488
 $175
 $313
 179 % $583
 $454
 $129
 28 %
Loss from discontinued operations, net of tax (9) —
 (9) NA
 (20) (30) 10
 33 % —
 (104) 104
 100 % (20) (134) 114
 85 %
Net income $133
 $167
 $(34) -20 % $75
 $249
 $(174) -70 % $488
 $71
 $417
 587 % $563
 $320
 $243
 76 %
Net cash provided by operating activities $232
 $567
 $(335) -59 % $453
 $1,185
 $(732) -62 % $763
 $855
 $(92) -11 % $1,216
 $2,040
 $(824) -40 %
DIVIDENDS DECLARED PER COMMON SHARE 0.05
 0.08
 $(0.03) -38 % 0.05
 0.08
 (0.03) -38 % $0.05
 $—
 $0.05
 NM
 $0.10
 $0.08
 $0.02
 NM
NM - Not Meaningful
Three months ended JuneSeptember 30, 2014:
Revenue increased $366445 million, or 9%11%, to $4.34.4 billion in the three months ended JuneSeptember 30, 2014 compared with $3.94.0 billion in the three months ended JuneSeptember 30, 2013. Including the unfavorable impact of foreign currency of $1545 million, the performance in each SBU was driven primarily by the following businesses and key operating drivers:

2830



US — Overall favorable varianceimpact of $35$36 million driven by higherregulatory retail ratesrate increases at DPL in Ohio, as a result of the ESP implemented in January 2014, and IPL in Indiana, due to higher pass-through costs, largelypartially offset by lower generation at DPL.decreased retail sales volume resulting from customer switching and mild weather.
Andes — Overall unfavorablefavorable impact of $1$75 million driven by higher contract and spot sales at Gener in Chile due to lower spot prices,and Chivor in Colombia. These results were offset by Argentina due to unfavorable foreign exchange rates, higher outages, and lower generation, partially offset by Chivor in Colombiahigher rates due to higher spot and contract prices.the Resolution 529 adjustment.
Brazil — Overall favorable impact of $303$273 million driven by higher volume at Uruguaiana, higher tariffs at Eletropaulo and Sul, primarily related to pass-through costs, and Tietê due to higher spot prices and contract prices, partially offset by unfavorable foreign exchange.prices.
MCAC — Overall unfavorable impact of $2 million driven by El Salvador due to lower pass-through energy costs, partially offset by higher contract and capacity prices in Panama.
EMEA — Overall favorable impact of $10 million driven by higher rates in the Dominican Republic and Puerto Rico, primarily pass-through costs. El Salvador also increased due to higher demand, partially offset by lower pass-through costs.
EMEA — Overall favorable foreign exchangeimpact of $39 million driven by new operations at the Jordan IPP4 plant which commenced operations in July 2014, partially offset by lower volume in Northern Ireland in the U.K. and Maritza in Bulgaria, partially offset by unfavorable foreign exchange in Kazakhstan.
Asia — Overall favorable impact of $21$12 million driven by higher generation at Kelanitissa in Sri Lanka, partially offset by a reduction in rates according to the PPA.PPA, and the Philippines due to higher contract demand, partially offset by lower rates.
Operating margin decreased $82160 million, or 9%17%, to $819767 million in the three months ended JuneSeptember 30, 2014 compared with $901927 million in the three months ended JuneSeptember 30, 2013. Including the unfavorable impact of foreign currency of $247 million, the performance in each SBU was driven primarily by the following businesses and key operating drivers:
US — Overall unfavorablefavorable impact of $3$16 million driven by DPL in Ohio due to unrealized derivative lossesregulatory retail rate increases and lower generation volumes,reduced fuel and purchase power costs, partially offset by higherdecreased retail rates. This decrease was partially offset by contributions from platform expansion projects at Southland and DPL (Tait). Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.sales volume as discussed above.
Andes — Overall neutral impact.favorable impact of $78 million driven by Chivor in Colombia due to higher sales as a result of higher inflows, as discussed above, and higher rates and Gener in Chile decreased due to lowerhigher coal and diesel availability and favorable contract and spot and contract margins,rates. These results were partially offset by Argentina due to higher fixed costs mainly driven by inflation, lower generation, and unfavorable foreign exchange rates, partially offset by higher rates related to Resolution 529.529 adjustment.
Brazil — Overall unfavorable impact of $43$262 million driven by UruguaianaTietê due to a non-recurring extinguishment of a liability based on a favorable arbitration decision of $53 millionlower water inflows which led to lower generation and an increase in the second quarter of 2013. Tietêenergy purchases at higher prices. Brazil was also decreased as a result of unfavorable foreign exchange rates and lower volumes, partially offset by higher spot prices. Partially offsetting these results, Eletropaulo increased driven by higher rates and volumes, partially offsetimpacted by higher fixed costs.costs, primarily at Eletropaulo. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
MCAC — Overall unfavorablefavorable impact of $3$33 million driven by a decrease in Panama,the Dominican Republic due to favorable impact of rates as a non-recurring settlement agreement relatedresult of lower fuel prices, higher PPA prices, and higher prices of gas sales to the Esti tunnel received during the second quarter of 2013 was partially offsetthird parties. In addition, Panama increased driven by compensation from the government of Panama received in the second quarter of 2014. El Salvador also decreased duerelated to higher energy losses and other fees. Offsetting these results, the Dominican Republic increased due to higher generation, somewhat offsetspot purchases driven by lower volume of gas sales to third parties and higher fuel prices.dry hydrological conditions.
EMEA — Overall unfavorablefavorable impact of $9 million driven by highernew operations at the Jordan IPP4 plant as discussed above, as well as better availability related to timing of scheduled outages and lower depreciation at Maritza and fewer outages and lower depreciation at Ebute. These results were partially offset by Kilroot in the U.K. due to higher rates, including income from energy price hedges.lower dispatch and rates.
Asia — Overall unfavorable impact of $18$26 million driven by lower plant availability and related costs in the Philippines andas well as a reduction in rates according to the PPA and higher outages and maintenance costs at Kelanitissa.Kelanitissa in Sri Lanka.
SixNine months ended JuneSeptember 30, 2014:
Revenue increased $478$923 million, or 6%8%, to $8.6$13 billion in the sixnine months ended JuneSeptember 30, 2014 compared with $8.1$12.1 billion in the sixnine months ended JuneSeptember 30, 2013. Including the unfavorable impact of foreign currency of $489$493 million, the performance in each SBU was driven primarily by the following businesses and key operating drivers:
US — Overall favorable variance of $150$186 million driven by higherregulatory retail rates and volumesrate increases at DPL in Ohio andas well as higher rates, primarily pass-through, at IPL in Indiana.
Andes — Overall unfavorablefavorable impact of $71$4 million driven by Chivor in Colombia due to higher spot and contract rates, somewhat offset by unfavorable foreign exchange rates, and Gener in Chile as a result of higher volume, partially offset by lower rates. Offsetting these results, Argentina decreased due to the impact of Resolution 95 since our fuel is provided andin which there is no longer a pass throughpass-through of fuel included in revenuesrevenue and unfavorable foreign exchange rates, partially offset by higher availability. Gener in Chile decreased as a result of lower contract and spot prices, partially offset by higher volume. Offsetting these trends, Chivor in Colombia increased due to higher spot and contract prices, somewhat offset by lower volume and unfavorable foreign exchange.

31



Brazil — Overall favorable impact of $319$592 million driven by higher volumes and higher tariffs, primarily pass-through costs, at Eletropaulo and Sul. Tietê also increased due to higher rates. Unfavorable foreign exchange partially offset these results.

29



MCAC — Overall unfavorable impact of $33$23 million driven by the Dominican Republic due to lower third party gas sales.sales, partially offset by higher PPA rates. El Salvador also decreased as a result of a one-time unfavorable adjustment to unbilled revenue and lower pass-through costs. Offsetting these results, Puerto Rico increased due to higher volume and rates and Panama increased as a result ofdue to higher prices.rates, partially offset by lower volume.
EMEA — Overall favorable impact of $58$97 million driven by the United Kingdom, as a resultstart of favorable foreign exchange, higher volumes,operations at Jordan IPP4 which commenced operations in July 2014 and the contributions from U.K. wind businesses, partially offset by lower rates. Maritza in Bulgaria also increased due to higher prices and favorable foreign exchange rates, partially offset by higher planned outages. The United Kingdom also increased as a result of favorable foreign exchange rates and the contributions from U.K. wind businesses, partially offset by lower rates.
Asia — Overall favorable impact of $56$68 million driven by higher generation at Kelanitissa in Sri Lanka.Lanka, partially offset by a reduction in rates according to the PPA, and the Philippines due to higher volume, partially offset by lower rates.
Operating margin decreased $37$197 million, or 2%8%, to $1.6$2.4 billion in the sixnine months ended JuneSeptember 30, 2014 compared with $1.7$2.6 billion in the sixnine months ended JuneSeptember 30, 2013. Including the unfavorable impact of foreign currency of $88$95 million the performance in each SBU was driven primarily by the following businesses and key operating drivers:
US — Overall unfavorablefavorable impact of $14$2 million driven by favorable results at US Generation including contributions from platform expansion projects at Southland and Tait energy storage project, combined with higher availability at Hawaii and increased market prices at Laurel Mountain. These results were largely offset by DPL as outages and lower gas availability in the first half of 2014 resulted in higher purchased power and related costs to supply higher demand from cold weather, as well as unrealized derivative losses. Contributions from platform expansion projects at Southland and DPL (Tait), combined with higher availability at Hawaii,losses, partially offset these results.by improvements in Q3 2014 resulting from increased retail rates and lower fuel costs. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
Andes — Overall unfavorablefavorable impact of $43$35 million driven by Chivor in Colombia due to higher generation resulting in higher spot and contract sales and ancillary services. These results were partially offset by Gener in Chile due to planned maintenance, lower contract and spot prices and higher spot energy purchases,lower availability, partially offset by full impact of new operations at Ventanas IV in 2014.2014 and lower fixed costs.
Brazil — Overall favorableunfavorable impact of $75$187 million driven by Tietê, as a result of due to lower water inflows which led to lower generation and an increase in energy purchases at higher prices. Eletropaulo also increased driven by higher tariffsprices and volume, partially offset by higher fixed costs. These results were partially offset by unfavorable foreign exchange rates and Uruguaiana due to a non-recurring extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013 at Uruguaiana.2013. Eletropaulo also decreased due to higher fixed costs and unfavorable foreign exchange rates, partially offset by higher tariffs and volume. Revenue increases due to pass-through costs do not have a corresponding impact on operating margin.
MCAC — Overall unfavorablefavorable impact of $19$14 million driven by Panama due to a non-recurring settlement in 2013the Dominican Republic mainly related to favorable rates and higher availability, partially offset by lower gas sales to third parties. Offsetting these results, Panama decreased as a result of dry hydrological conditions, which resulted in lower generation and higher energy purchases and the 2013 Esti tunnel.tunnel settlement of $31 million, partially offset by compensation from the government of Panama as well as lower fixed costs and El Salvador also decreased due to one-time unfavorable adjustment to unbilled revenue. Partially offsetting these results, the Dominican Republic increased due to higher availability and higher spot sales.
EMEA — Overall favorable impact of $10$19 million driven by the United Kingdom,new operations at Jordan IPP4 as a result ofdiscussed above, as well as Ebute due to better operations and lower depreciation and Kazakhstan due to higher generation volume and rates, at Kilroot, higher dispatch at Ballylumford, and the contributions from U.K. wind businesses.partially offset by unfavorable foreign exchange rates.
Asia — Overall unfavorable impact of $46$72 million driven by Masinloc in the Philippines, due to lower plant availability and the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013. Kelanitissa also decreased due to a reduction in rates according to the PPA.

General and administrative expenses
General and administrative expenses decreased $18 million, or 2%15%, to $5245 million for the three months ended JuneSeptember 30, 2014 mainlyprimarily due to lower business developmentemployee related costs and travel costs, partially offset by an increase in professional fees and employee related costs.fees.
General and administrative expenses decreased $412 million, or 4%8%, to $103148 million for the sixnine months ended JuneSeptember 30, 2014 mainlyprimarily due to lower employee related and business development costs and travel costs, partially offset by an increase in professional fees.costs.

32



Interest expense
Interest expense decreaseincreased $1432 million, or 4%9%, to $323390 million for the three months ended JuneSeptember 30, 2014. The decreaseincrease was primarily due to an increase in regulatory liabilities and increased interest rates in Brazil, and the reversaltermination of $48 million of contingent interest accruals associated with disputed purchased energy obligations at Sul, andrate hedges upon early debt retirement. These increases were partially offset by a reduction in debt. These decreases were offset bycorporate debt balances.
Interest expense increased $21 million, or 2%, to $1.1 billion for the nine months ended September 30, 2014. The increase was primarily due to an increase in regulatory liabilities and increased interest rates in Brazil, and a $34 million gain in the prior year related to the recognition of ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges.
Interest expense decreased $11 million, or 2%, to $696 million for the six months ended June 30, 2014. The decrease was primarily due to the reversal of $48 million of contingent interest accruals associated with disputed purchased energy obligations at Sul, and These increases were partially offset by a reduction in debt. These decreases were offset by a $34 million gain in the prior year related to the recognition of ineffectiveness on derivative interest rate swaps accounted for as cash flow hedges.corporate debt balances.
See Note 8. — Debt included in Item 1. — Financial Statements of this Form 10-Q for further information.

30



Interest income
Interest income increasedecreased $1016 million, or 16%19%, to $7369 million for the three months ended JuneSeptember 30, 2014. The increasedecrease was primarily in Brazil, due to higher interest income recognized on FONINVEMEM III receivables in Argentina in the prior year.
Interest income decreased $8 million, or 4%, to $205 million for the nine months ended September 30, 2014. The decrease was primarily due to higher interest income recognized on FONINVEMEM III receivables in Argentina in the prior year, partially offset by an increase in regulatory assets partially offset by lower receivable balances.
Interest income increased $8 million, or 6%, to $136 million for the six months ended June 30, 2014. The increase was primarily in Brazil, due to an increase in regulatory assets, partially offset by lower receivable balances.at Brazil.
Loss on extinguishment of debt
Loss on extinguishment of debt was $15$47 million and $149$196 million for the three and sixnine months ended JuneSeptember 30, 2014, respectively, primarily related to early extinguishment of debt at the Parent Company. See Note 8. — Debt included in Item 1. — Financial Statements of this Form 10-Q for further information.
Loss on extinguishment of debt was $0 million and $212 million for the three and nine months ended September 30, 2013, respectively, related to the loss on the early retirement of recourse debt at the Parent Company and the loss on the early extinguishment of debt at Masinloc. See Note 8. — Debt included in Item 1. — Financial Statements of this Form 10-Q for further information.
Other income and expense
See discussion of the components of other income and expense in Note 13 — Other Income and Expense included in Item 1. — Financial Statements of this Form 10-Q for further information.
Gain on sale of investments
There was no gain on sale of investments for the three months ended June 30, 2014. Gain on sale of investments for the three months ended JuneSeptember 30, 2014 was $362 million, which was primarily related to the sale of 45% of our investment in Masinloc and 100% of our interest in UK Wind. See Note 11 — Equity included in Item 1. — Financial Statements of this Form 10-Q for further information. Gain on sale of investments for the three months ended September 30, 2013 was $203 million, primarily related to the sale of the remaining 20%our 10% equity interest in Cartagena.Trinidad Generation Unlimited.
Gain on sale of investments for the sixnine months ended JuneSeptember 30, 2014 was $1$363 million, which is primarily related to the sale of Chengdu, an equityour investment in China.Masinloc and UK Wind, as discussed above. See Note 11 — Equity included in Item 1. — Financial Statements of this Form 10-Q for further information. Gain on sale of investments for the sixnine months ended JuneSeptember 30, 2013 was $23$26 million, primarily related to the sale of theour remaining 20% interest in Cartagena as well as the sale of our investment in Trinidad, as discussed above.
Goodwill Impairment
Goodwill impairment expense for the three and sixnine months ended JuneSeptember 30, 2014 was $0 million and $154 million, respectively. There was no$58 million of goodwill impairment for the three and sixnine months ended JuneSeptember 30, 2013. See Note 14 — Goodwill Impairment included in Item 1. — Financial Statements of this Form 10-Q for further information.
Asset impairment expense
Asset impairment expense was $6315 million and $75$90 million for the three and sixnine months ended JuneSeptember 30, 2014, and $016 million and $48$64 million for the three and sixnine months ended JuneSeptember 30, 2013. See Note 15 — Asset Impairment Expense included in Item 1. — Financial Statements of this Form 10-Q for further information.

33



Foreign currency transaction gains (losses)
Foreign currency transaction gains (losses) were as follows:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 ($ in millions) ($ in millions)
Chile 2
 $(10) $(6) $(14) (21) $(1) $(27) $(15)
Brazil 1
 (8) 6
 (10) (7) —
 (1) (10)
Philippines 6
 (7) 8
 (7)
The AES Corporation (1) 7
 (3) (17) (20) 15
 (23) (2)
Argentina 1
 —
 (14) (3) (19) 16
 (33) 13
Other (2) —
 (3) 3
 (12) 2
 (7) (2)
Total(1)
 $7
 $(18) $(12) $(48) $(79) $32
 $(91) $(16)

(1) 
Includes $10$6 million and $17$23 million in gains on foreign currency derivative contracts for the three months ended JuneSeptember 30, 2014 and 2013, respectively, and $43$49 million and $19$42 million in gains on foreign currency derivative contracts for the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
There were no significant foreign currency transaction gains or losses for the three months ended June 30, 2014.
The Company recognized net foreign currency transaction losses of $18$79 million for the three months ended JuneSeptember 30, 20132014 primarily due to:
losses of $10$21 million in Chile, which were primarily due to a 5% weakeningan 8% devaluation of the Chilean Peso, resulting in lossesa loss at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos,

31



primarily cash, accounts receivables and VAT receivables. These receivables;
losses of $20 million at The AES Corporation were primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the period, partially offset by incomegains related to foreign currency options; and
losses of $19 million in Argentina, which were primarily related to AES Argentina Generacion (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt and losses on the purchase of Argentine sovereign bonds at Termoandes (a U.S. Dollar functional currency subsidiary). Additionally, losses were incurred on foreign currency derivatives.embedded derivatives related to government receivables at AES Argentina Generacion and a 3% devaluation of the Argentine Peso.
The Company recognized foreign currency transaction lossesgains of $12$32 million for the sixthree months ended JuneSeptember 30, 20142013 primarily due to:
gains of $15 million at The AES Corporation, which were primarily due to increases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the strengthening of the Euro and British Pound, partially offset by losses related to foreign currency option purchases; and
gains of $14$16 million in Argentina, which were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses related to the 8% devaluation of the Argentine Peso, by 25%, resulting in losses at AES Argentina GenerationGeneracion (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) mainly associated with cash and accountaccounts receivable balances in the local currency.
The Company recognized foreign currency transaction losses of $91 million for the nine months ended September 30, 2014 primarily due to:
losses of $33 million in Argentina, which were primarily related to the 29% devaluation of the Argentine Peso, resulting in losses at AES Argentina Generacion (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) mainly associated with cash and accounts receivable balances in the local currency and the foreign currency losses on the purchase of Argentine sovereign bonds. These losses were partially offset by a gain on a foreign currency embedded derivativederivatives related to government receivables at AES Argentina Generation related to government receivables.
The Company recognized foreign currency transaction losses of $48 million for the six months ended June 30, 2013 primarily due to:Generacion;
losses of $1727 million in Chile, which were primarily due to a 14% devaluation of the Chilean Peso, resulting in a loss at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean Pesos (primarily cash, accounts receivables and VAT receivables). These losses were partially offset by foreign currency derivatives; and
losses of $23 million at The AES Corporation were primarily due to decreases in the valuation of intercompany notes receivable denominated in foreign currency, resulting from the weakening of the Euro and British Pound during the year, partially offset by gains related to foreign currency options;options.
The Company recognized foreign currency transaction losses of $16 million for the nine months ended September 30, 2013 primarily due to:

34



losses of $1415 million in Chile, which were primarily due to a 6% weakening5% devaluation of the Chilean Peso, resulting in losses at Gener (a U.S. Dollar functional currency subsidiary) from working capital denominated in Chilean pesos, pesos(primarily cash, accounts receivable and VAT receivables. Additionalreceivables). These losses were related topartially offset by foreign currency derivatives; and
losses of $10 million in Brazil, which were mainly related to commercial liabilities denominated in U.S. Dollars due to the 8% weakening9% devaluation of the Brazilian Real versus the U.S. Dollar.Dollar; partially offset by
gains of $13 million in Argentina, which were primarily due to a gain on a foreign currency embedded derivative related to government receivables, partially offset by losses due to the 18% devaluation of the Argentine Peso which resulted in losses at AES Argentina Generacion (an Argentine Peso functional currency subsidiary) associated with its U.S. Dollar denominated debt, and losses at Termoandes (a U.S. Dollar functional currency subsidiary) mainly associated with cash and accounts receivables in the local currency.
Other non-operating expense
Total other non-operating expense was $44$16 million and $60 million for the three and sixnine months ended JuneSeptember 30, 2014, which is attributable to the impairment loss of $44 million recognized in conjunction with the sale of the Company's 50% ownership interest in Silver Ridge Power, LLC ("SRP"). There was no$122 million of other non-operating expense for the three and sixnine months ended JuneSeptember 30, 2013. See Note 16 — Other Non-Operating Expense included in Item 1. — Financial Statements of this Form 10-Q for further information.
Income tax expense
Income tax expense increasedecreased $8134 million, or 107%27%, to $15792 million for the three months ended JuneSeptember 30, 2014 compared to $76126 million for the three months ended JuneSeptember 30, 2013. The Company’s effective tax rates were 38%15% and 19%28% for the three months ended JuneSeptember 30, 2014 and 2013, respectively.
The net increasedecrease in the effective tax rate for the three months ended JuneSeptember 30, 2014 compared to the same period in 2013 was due, in part, to certain asset impairments recorded this quarter with no related tax benefit and net favorable resolutionthe current period sale of various uncertain tax positions and lower tax expense from certain higher tax jurisdictions45% of the Company's interest in Masin - AES Pte Ltd., which owns the Company's business interests in the second quarterPhilippines, and the current period sale of 2013.the Company's interests in four U.K. wind projects. Neither of these transactions gave rise to income tax expense. Further, the 2014 effective tax rate benefited from a change in tax status at a subsidiary operating in the Dominican Republic, partially offset by the unfavorable impact of Chilean income tax law reform enacted this quarter. See Note 15 —11 Asset Impairment Expense- Equity for additional information regarding asset impairment.the sale of 45% of the Company's interest in Masin - AES Pte Ltd. See Note 19 - Dispositions for additional information regarding the sale of the Company's interests in four U.K wind projects. See Note 17 - Income Taxes for additional information regarding the Chilean tax law reform and change in tax status at a Dominican Republic subsidiary.    
Income tax expense increased $52$18 million, or 33%6%, to $211$303 million for the sixnine months ended JuneSeptember 30, 2014 compared to $159$285 million for the sixnine months ended JuneSeptember 30, 2013. The Company’s effective tax rates were 39%27% and 22%24% for the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
The net increase in the effective tax rate for the sixnine months ended JuneSeptember 30, 2014 compared to the same period in 2013 was due, in part, to the unfavorable impact of Chilean income tax law reform enacted this quarter and to the nondeductible goodwill impairments recorded during the first quarter of 2014, and certain asset impairments recordedoffset by sales this quarter with no related tax benefit.of 45% of the Company's interest in Masin - AES Pte Ltd., which owns the Company's business interests in the Philippines and of the Company's interests in four U.K. wind projects. Further, the 2013 effective tax rate benefited from the extension of a favorable U.S. tax law in the first quarter of 2013 impacting distributions from certain non-U.S. subsidiaries, net favorable resolution of various uncertain tax positions, and lower tax expense from certain higher tax jurisdictions. See Note 17 - Income Taxes for additional information regarding the Chilean tax law reform. See Note 14 —- Goodwill Impairment and Note 15 — Asset Impairment Expense for additional information regarding goodwill and asset impairment, respectively.impairment. See Note 11 - Equity for additional information regarding the sale of 45% of the Company's interest in Masin - AES Pte Ltd. See Note 19 - Dispositions for additional information regarding the sale of the Company's interests in four U.K wind projects.    
Our effective tax rate reflects the tax effect of significant operations outside the United States, which are generally taxed at rates lower than the U.S. statutory rate of 35%. A future proportionate change in the composition of income before income taxes from foreign and domestic tax jurisdictions could impact our periodic effective tax rate.

32



Net equity in earnings of affiliates
Net equity in earnings of affiliates increasedecreased $1821 million to a loss of $206 million for the three months ended JuneSeptember 30, 2014. The decrease was primarily due to lower net income at Guacolda resulting from comprehensive tax reforms enacted by the Chilean government. See Note 17 - Income Taxes for additional information regarding the Chilean tax law reform.
Net equity in earnings of affiliates increased $18 million to $39 million for the nine months ended September 30, 2014. The increase was primarily due to a loss on an embedded foreign currency derivative at Entek in 2013.

Net equity in earnings of affiliates increased $39 million to $45 million for the six months ended June 30, 2014. The increase was primarily due to increased earnings at Guacolda due to the sale of a transmission line, as well as a loss on an embedded foreign currency derivative at Entek in 2013.
35



Income from continuing operations attributable to noncontrolling interests
Income from continuing operations attributable to noncontrolling interests decreased $27144 million, or 16%88%, to $13920 million for the three months ended JuneSeptember 30, 2014. The decrease was primarily due to decreased grossoperating margin at Uruguaiana caused by a favorable arbitration settlementboth Tietê and Eletropaulo because of higher prices of energy purchased in 2013.the spot market and increased fixed costs related to pension, respectively.
Income from continuing operations attributable to noncontrolling interests decreased $10$154 million, or 4%34%, to $275$295 million for the sixnine months ended JuneSeptember 30, 2014. The decrease was primarily due to decreased operating margin at Tietê and Eletropaulo, as discussed above, lower operating income at Panama related to lower hydrology, and decreased gross margin at Uruguaiana as discussed above, partially offsetcaused by increased operating income as a result of higher prices of the energy soldfavorable arbitration settlement in spot market at Tietê.2013.
Discontinued operations
Total discontinued operations was a net loss of $60 million and $0116 million for the three months ended JuneSeptember 30, 2014 and 2013, respectively, and a net loss of $29 million and $32$148 million for the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively. See Note 1718 — Discontinued Operations and Held-for-Sale Businesses included in Item 1. — Financial Statements of this Form 10-Q for further information.
Effective July 1, 2014, the Company prospectively adopted ASU No. 2014-08, which significantly changes the existing accounting guidance on discontinued operations. See Note 1 — Financial Statement Presentation included in Item 1. — Financial Statements of this Form 10-Q for further information.
Net income attributable to The AES Corporation
Net income attributable to The AES Corporation decreasedincreased $34417 million to $133488 million in the three months ended JuneSeptember 30, 2014 compared to a net. Net income attributable to AES of $167 million in the three months ended JuneSeptember 30, 2013 was $71 million.
The key drivers of the decreaseincrease include:
highergain on sale of investment from the sale of a noncontrolling interest at Masinloc in 2014;
lower impairments of equity method investments in 2014;
goodwill impairments at Ebute during 2013; and
lower effective tax rate;rate.
higher asset impairment expense;
lower gross margin;
higher other-than-temporary impairment expense in 2014; and
lower gains from ineffectiveness on interest rate swaps in 2014.
These decreasesincreases were partially offset by:
lowerhigher expenses resulting from debt extinguishments in 2014; and
higher foreign currency transaction losses in 2014.
Net income attributable to The AES Corporation decreased $174increased $243 million to $75$563 million in the sixnine months ended JuneSeptember 30, 2014 compared to net2014. Net income attributable to AES of $249 million in the sixnine months ended JuneSeptember 30, 2013. 2013 was $320 million.
The key drivers of the decreaseincrease include:
gain on sale of investment from the sale of a noncontrolling interest at Masinloc in 2014; and
lower impairments of equity method investments in 2014.
These increases were partially offset by:
goodwill impairments in the US;
higher effective tax rate;
lower gross margin, as discussed above;
higher other-than-temporary impairment expenseUS recognized in in the first quarter of 2014;
higher other income in 2013 relating to the gain from the termination of the PPA at Beaver Valley;interest expense; and
lower gains from ineffectiveness on interest rate swaps in 2014.
These decreases were partially offset by:
lower expenses resulting from debt extinguishments in 2014; and
lowerhigher foreign currency transaction losses in 2014.

33



Net cash provided by operating activities
Net cash provided by operating activities decreased $732824 million to $453 million during the six months endedJune 30, 2014 compared to $1.2 billion during the sixnine months ended JuneSeptember 30, 2014 compared to $2 billion during the nine months endedSeptember 30, 2013. Please refer to Consolidated Cash Flows -- Operating Activities within Capital Resources and Liquidity section for further discussion.
Net cash provided by operating activities decreased $335$92 million, or 59%11%, to $232$763 million in the three months ended JuneSeptember 30, 2014 compared with $567$855 million during the three months ended JuneSeptember 30, 2013.
Operating cash flow of $232$763 million for the three months ended JuneSeptember 30, 2014 resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization and impairment expenses, partially offset byas well as a net usefavorable change of cash for operating activities of $441$89 million in operating assets and liabilities. This net use of cash for operating activities of $441 million was primarily due to the following:

a decrease of $609 million in accounts payable and other current liabilities, primarily due to a decrease in energy purchases at Eletropaulo and Sul as well as lower interest payments at the Parent Company; partially offset by
36



an increase of $128$253 million in other liabilities primarily due to increases in regulatory liabilities at Eletropaulo and Sul which will be refunded to customers through future tariffs;
an increase of $180 million in accounts payable and other current liabilities, primarily due to an increase in energy purchases at Tietê and Sul offset by a decrease in working capital at Uruguaiana; partially offset by
an increase of $128$182 million in accounts receivable primarily due to higher sales at Eletropaulo and Sul partially offset by a decrease in working capital at Uruguaiana; and
an increase of $123 million in other assets primarily due to a decrease in noncurrent regulatory assetsincreases at Eletropaulo and Sul resulting from funds received from the offtakerhigher energy costs due to partially cover higher costs of energy purchased.unfavorable weather conditions.
Net cash provided by operating activities was $567$855 million during the three months ended JuneSeptember 30, 2013. Operating cash flows2013 and resulted primarily from net income adjusted for non-cash items, principally depreciation and amortization, gains and losslosses on extinguishment of debt partially offset bysales and disposals and impairment charges, as well as a net usefavorable change of cash for operating activities of $161$55 million in operating assets and liabilities. This net use of cash for operating activities of $161 million was primarily due to the following:
a decrease of $426$348 million in prepaid expenses and other current assets primarily due to cash received from the regulator at Eletropaulo;
an increase of $68 million in net income tax and other tax payables primarily due to accruals for new current tax liabilities offset by payments of income taxes; partially offset by
a decrease of $326 million in accounts payable and other current liabilities primarilymainly due to reduced operations and the extinguishment of a liability based on a favorable arbitration decision at Uruguaiana, a decrease in current regulatory liabilities at Eletropaulo higher interest payments at the Parent Company and DPLSul; and higher energy purchases at Tietê;
an increase of $102 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo, resulting from higher priced energy purchases which are recoverable through future tariffs; partially offset by
a decrease of $247 million in prepaid expenses and other current assets due to a decrease in current regulatory assets, for the recovery of prior period tariff cycle energy purchases and regulatory charges at Eletropaulo as well as the recovery of a receivable from the regulator at Sul; and
a decrease of $149$56 million in accounts receivable due to reduced operationshigher volume of energy sales at UruguaianaEletropaulo and a lower tariffcollections at Eletropaulo.Maritza.
Non-GAAP Measures
Adjusted Operating Margin, adjusted pretax contribution (“Adjusted PTC”)PTC and adjusted earnings per share (“Adjusted EPS”) are non-GAAP supplemental measures that are used by management and external users of our consolidated financial statements such as investors, industry analysts and lenders.
Adjusted Operating Margin
Operating Margin is defined as revenue less cost of sales. Cost of sales includes costs incurred directly by the businesses in the ordinary course of business, such as:
Electricity and fuel purchases,
Operations and maintenance costs,
Depreciation and amortization expense,
Bad debt expense and recoveries,
General administrative and support costs at the businesses, and
Gains or losses on derivatives associated with the purchase and sale of electricity or fuel.
We define Adjusted Operating Margin as Operating Margin, adjusted for the impact of noncontrolling interests, excluding unrealized gains or losses related to derivative transactions.
The GAAP measure most comparable to Adjusted Operating Margin is operating margin. We believe that Adjusted Operating Margin better reflects the underlying business performance of the Company. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the

34



Company, as well as the variability due to unrealized derivatives gains or losses. Adjusted Operating Margin should not be construed as an alternative to Operating Margin, which is determined in accordance with GAAP.
Adjusted Pretax Contribution and Adjusted Earnings Per Share
We define adjusted pretax contribution ("Adjusted PTC")PTC as pretax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt. Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the aforementioned items.
Adjusted PTC reflects the impact of noncontrolling interests and excludes the items specified in the definition above. In addition to the revenue and cost of sales reflected in operating margin, adjusted pretax contributionAdjusted PTC includes the other components of our income statement, such as:
General and administrative expense in the corporate segment, as well as business development costs;

37



Interest expense and interest income;
Other expense and other income;
Realized foreign currency transaction gains and losses; and
Net equity in earnings of affiliates.
We define Adjusted EPS as diluted earnings per share from continuing operations excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions, (b) unrealized foreign currency gains or losses, (c) gains or losses due to dispositions and acquisitions of business interests, (d) losses due to impairments, and (e) costs due to the early retirement of debt.
The GAAP measure most comparable to Adjusted PTC is income from continuing operations attributable to The AES Corporation. The GAAP measure most comparable to Adjusted EPS is diluted earnings per share from continuing operations. We believe that Adjusted PTC and Adjusted EPS better reflect the underlying business performance of the Company and are considered in the Company’s internal evaluation of financial performance. Factors in this determination include the variability due to unrealized gains or losses related to derivative transactions, unrealized foreign currency gains or losses, losses due to impairments and strategic decisions to dispose of or acquire business interests or retire debt, which affect results in a given period or periods. In addition, for Adjusted PTC, earnings before tax represents the business performance of the Company before the application of statutory income tax rates and tax adjustments, including the effects of tax planning, corresponding to the various jurisdictions in which the Company operates. Adjusted PTC and Adjusted EPS should not be construed as alternatives to income from continuing operations attributable to The AES Corporation and diluted earnings per share from continuing operations, which are determined in accordance with GAAP. 
Reconciliations of Non-GAAP Measures
Adjusted Operating Margin
Reconciliation of Adjusted Operating Margin to Operating Margin Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
Adjusted Operating Margin (
Adjusted Pretax Contribution: For a reconciliation of Adjusted PTC to net income from continuing operations, see Note 12 — Segments included in Item 1. — Financial Statements of this Form 10-Q.

35



Adjusted EPS
 Three Months Ended June 30, Six Months Ended June 30,  Three Months Ended September 30, Nine Months Ended September 30, 
Reconciliation of Adjusted Earnings Per Share 2014 2013 2014 2013  2014 2013 2014 2013 
Diluted earnings per share from continuing operations $0.20
 $0.22
 $0.13
 $0.37
  $0.67
 $0.23
 $0.81
 $0.61
 
Unrealized derivative (gains) losses (1)
 (0.02) (0.05) (0.03) (0.03)  0.01
 —
 (0.02) (0.04) 
Unrealized foreign currency transaction (gains) losses (2)
 —
 0.04
 0.03
 0.05
  0.06
 (0.02) 0.07
 0.04
 
Disposition/acquisition (gains) losses —
 (0.03)
(3) 
—
 (0.03)
(4) 
 (0.51)
(3) 
—
 (0.51)
(4) 
(0.03)
(5) 
Impairment losses 0.09
(5) 
—
 0.26
(6) 
0.05
(7) 
 0.08
(6) 
0.18
(7) 
0.34
(8) 
0.23
(9) 
Loss on extinguishment of debt 0.01
(8) 
0.17
(9) 
0.14
(10 
) 
0.21
(11) 
 0.06
(10) 
—
 0.20
(11 
) 
0.20
(12) 
Adjusted earnings per share $0.28
 $0.35
 $0.53
 $0.62
  $0.37
 $0.39
 $0.89
 $1.01
 
_____________________________
(1) 
Unrealized derivative (gains) losses were net of income tax per share of $(0.01)$0.00 and $(0.02)$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $(0.01) and $(0.02)$(0.03) in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
(2) 
Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00$0.03 and $0.00$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $0.01$0.04 and $0.01 in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
(3) 
Amount primarily relates to the gain from the sale of the remaining 20%a noncontrolling interest in Cartagena for $20Masinloc of $283 million ($15283 million, or $0.02$0.39 per share, net of income tax per share of $0.01).$0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per

38



share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction.
(4) 
Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction.
(5)
Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena forof $20 million ($1514 million, or $0.02 per share, net of income tax per share of $0.01), the gain from the sale of wind turbines for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00), the gain from the sale of Trinidad for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00) as well as the gain from the sale of Chengdu, an equity method investment in China forof $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00).
(5)(6) 
Amount primarily relates to the assetother-than-temporary impairment of our equity method investment at EbuteEntek of $52$18 million ($3412 million, or $0.05$0.02 per share, net of income tax per share of $0.02) and$0.01), the asset impairment at NewfieldEbute of $11$15 million ($6 million, or $0.00 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).
(6)
Amount primarily relates to the goodwill impairments at DPLER of $136 million ($92 million, or $0.13 per share, net of income tax per share of $0.06), at Buffalo Gap of $18 million ($1823 million, or $0.03 per share, net of income tax per sharenoncontrolling interest of $0.00)$1 million and asset impairments at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02)$(0.01)), at Newfieldand a tax benefit of $11$25 million ($6 million, or $0.000.03 per share, net of income tax per share of $0.00),share) associated with the previously recognized goodwill impairment at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).DPLER.
(7) 
Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also includes asset impairment at Beaver ValleyItabo (San Lorenzo) of $46$15 million ($346 million, or $0.05$0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).
(8) 
Amount primarily relates to the loss on early retirementgoodwill impairments at DPLER of debt$136 million ($117 million, or $0.16 per share, net of income tax per share of $0.03), and at CorporateBuffalo Gap of $13$18 million ($18 million, or $0.03 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($57 million, or $0.08 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01), at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.01), and at Newfield of $11 million ($6 million, or $0.00 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00) as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($28 million, or $0.04 per share, net of income tax per share of $0.02) and at Entek of $18 million ($12 million, or $0.02 per share, net of income tax per share of $0.01).
(9) 
Amount primarily relates to the loss on early retirementother-than-temporary impairment of debtour equity method investment at CorporateElsta in the Netherlands of $163$122 million ($12189 million, or $0.16$0.12 per share, net of income tax per share of $0.06)$0.04). Amount also includes the asset impairment at Beaver Valley of $46 million ($33 million, or $0.04 per share, net of income tax per share of $0.02), the asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as the goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).
(10) 
Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $145$43 million ($9925 million, or $0.14$0.03 per share, net of income tax per share of $0.06)$0.03), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $6 million ($3 million, or $0.00 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(11) 
Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $188 million ($123 million, or $0.17 per share, net of income tax per share of $0.09), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $8 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(12)
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $165 million ($123120 million, or $0.16 per share, net of income tax per share of $0.06) and at Masinloc of $43 million ($29 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01).

Operating Margin and Adjusted PTC Analysis
US SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change
 ($’s in millions) ($’s in millions)
Operating Margin $144
 $147
 $(3) -2 % $278
 $292
 $(14) -5 % $222
 $206
 $16
 8% $500
 $498
 $2
 —%
Noncontrolling Interests Adjustment —
 —
     —
 —
     —
 —
     —
 —
    
Derivatives Adjustment —
 (13)     9
 —
     5
 2
     14
 2
    
Adjusted Operating Margin $144
 $134
 $10
 7 % 287
 292
 $(5) -2 % $227
 $208
 $19
 9% 514
 500
 $14
 3%
Adjusted PTC $80
 $63
 $17
 27 % $155
 $196
 $(41) 21 % $156
 $132
 $24
 18% $311
 $328
 $(17) 5%
Operating marginMargin for the three months ended JuneSeptember 30, 2014 decreased $3increased $16 million, or 2%8%. This performance was driven primarily by the following businessesbusiness and key operating drivers:
DPL decreased $19 million, primarily due to a $15 million impact from unrealized mark-to-market gains on derivatives in 2013 that did not recur, combined with a decrease in sales volumes, partially offset by an increase in retail rates.
This decrease was partially offset by:
US GenerationOhio increased by $14 million, primarily due to $8regulatory retail rate increases and reduced fuel and purchase power costs of $41 million, relating to the implementationpartially offset by decreased retail sales of the synchronous condensers to provide ancillary services in June 2013 at Southland, $3$25 million due to the completion of

36



the Tait energy storage project at DPL in September 2013,resulting from customer switching and an increase in market prices relating to production at Laurel Mountain of $2 million. mild weather.
Adjusted Operating Margin increased $1019 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin.
Adjusted PTC increased $1724 million driven by a $3$5 million gain recognized from proceeds relatingat Buffalo Gap, due to a bankruptcy settlement at Laurel Mountain,an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest (See Note 1 — General and Summary of Significant Accounting Policies — Noncontrolling Interests included in Item 8. — Financial Statements and Supplementary Data in the Company's 2013 Form 10-K) as well as the increase of $1019 million in Adjusted Operating Margin described above.

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Operating marginMargin for the sixnine months ended JuneSeptember 30, 2014 decreased $14increased $2 million, or 5%0.4%. This performance was driven primarily by the following businesses and key operating drivers:
DPL decreased $48US Generation increased by $32 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $7 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 and lower fixed costs at Southland, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and
IPL in Indiana increased $4 million driven by higher wholesale and retail margin of $13 million, partially offset by higher fixed costs and depreciation of $9 million.
These increases were partially offset by:
DPL decreased $34 million, primarily due to decreases of $31 million attributable to outages and lower gas availability, which resulted in higher purchased power and related costs to supply higher demand from cold weather during the first quarter as well as outages and lower gains on unrealized derivativederivatives of $13 million in the second quarter.
This decrease was The results above were partially offset by:
US Generation increased by $33 million, primarily due to $11 millionimprovements in Q3 resulting from increased availability as a resultretail rates and lower fuel costs of fewer outages at Hawaii, $11 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 at Southland, $8 million at Laurel Mountain due to increased market prices relating to production, and $6 million due to the completion 2013 of the Tait energy storage project in September 2013.$16 million.
Adjusted Operating Margin decreased $5increased $14 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin.
Adjusted PTC decreased $41$17 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, partially offset by an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $10 million, settlements at Laurel Mountain of $6 million, as well as the decreaseincrease of $5$14 million in Adjusted Operating Margin described above.
Andes SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change
 ($’s in millions) ($’s in millions)
Operating Margin $148
 $148
 $—
 —% $239
 $282
 $(43) -15 % $212
 $134
 $78
 58% $451
 $416
 $35
 8%
Noncontrolling Interests Adjustment 32
 34
     56
 71
     53
 29
     109
 100
    
Derivatives Adjustment —
 —
     —
 —
     —
 —
     —
 —
    
Adjusted Operating Margin $116
 $114
 $2
 —% $183
 $211
 $(28) -13 % $159
 $105
 $54
 51% $342
 $316
 $26
 8%
Adjusted PTC $104
 $88
 $16
 18% $157
 $169
 $(12) 7 % $120
 $109
 $11
 10% $277
 $278
 $(1) —%
Including the neutralunfavorable impact of foreign currency translation and remeasurement of $3 million, operating margin for the three months ended JuneSeptember 30, 2014 remained flat.increased $78 million, or 58%. This performance was driven primarily by the following businesses and key operating drivers:
Chivor in Colombia increased $55 million as higher inflows resulted in higher generation and spot sales of $44 million as well as higher rates of $6 million.
Gener in Chile increased $30 million due to higher coal and diesel availability of $19 million, and favorable contract and spot prices of $10 million in the SIC market.
This increase was offset by:
Argentina increaseddecreased $6 million driven by higher rates of $17 million related to the Resolution 529 adjustment (retroactive from February 2014), offset by higher fixed costs of $9 million mainly caused by inflation, adjustments.
This increase was offset by:
Gener in Chile decreased $4 million due to lower spot prices and lower margins on Energy Plus contracts at Termoandesgeneration of $8$7 million, and lower contract prices at Norgenerunfavorable foreign exchange rate impact of $5$4 million, partially offset by lower fixed costs from lower maintenancehigher rates of $8 million; and
Chivor in Colombia decreased $2$16 million from higher fixed costs related to the tunnel maintenance, partially offset by higher ancillary services and spot prices.Resolution 529 adjustment.
Adjusted Operating Margin increased $254 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.

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Adjusted PTC increased $1611 million, driven by the increase of $254 million in Adjusted Operating Margin described above, partially offset by a non-recurring benefit of $20 million from FONINVEMEM III interest income on receivables in 2013 in Argentina and lower realized foreign currency lossesequity in earnings at Guacolda in Chile of $15 million in Chile.$12 million.
Including the unfavorable impact of foreign currency translation and remeasurement of $3$7 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $43increased $35 million, or 15%8%. This performance was driven primarily by the following businesses and key operating drivers:

40



Chivor in Colombia increased $52 million largely driven by significantly higher generation of $51 million resulting in higher spot and contract sales and ancillary services.
This increase was offset by:
Gener in Chile decreased $44$14 million, largely driven by lower availability in the first quarter due primarily to planned outages of $22 million, a reduction of $39$29 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $6 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $9 million;$10 million.
Chivor in ColombiaArgentina decreased $3$4 million driven by higher fixed costs as described above and lower foreign currency exchange rates,of $25 million driven by higher inflation; partially offset by higher prices and AGC sales; and
Argentina increased $3 million driven by higher rates of $17$21 million as a result of the impact of Resolution 529, partially offset by higher fixed costs of $16 million driven by higher inflation adjustment.529.
Adjusted Operating Margin decreased $28increased $26 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC decreased $12$1 million, driven by the decreaseincrease of $28$26 million in Adjusted Operating Margin described above, partiallyprimarily offset by higher equity earningsa non-recurring benefit in 2013 from the sale of a transmission line of Guacolda and lower realized foreign currency losses in Chile.FONINVEMEM III interest income on receivables as discussed above.
Brazil SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change
 ($’s in millions) ($’s in millions)
Operating Margin $270
 $313
 $(43) -14 % $591
 $516
 $75
 15% $44
 $306
 $(262) -86 % $635
 $822
 $(187) -23 %
Noncontrolling Interests Adjustment 188
 223
     423
 372
     29
 208
     453
 580
    
Derivatives Adjustment —
 —
     —
 —
     —
 —
     —
 —
    
Adjusted Operating Margin $82
 $90
 $(8) -9 % $168
 $144
 $24
 17% $15
 $98
 $(83) -85 % $182
 $242
 $(60) -25 %
Adjusted PTC $115
 $78
 $37
 47 % $184
 $120
 $64
 53% $—
 $84
 $(84) -100 % $184
 $204
 $(20) 10 %
Including the unfavorable impact of foreign currency translation of $23 million, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreased $43$262 million, or 14%86%. This performance was driven primarily by the following businesses and key operating drivers:
Uruguaiana decreased $39 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation volumes from a temporary restart of operations;
Tietê decreased $12$202 million, driven by unfavorable foreign exchange rates of $16 million anddue to lower hydrology which led to lower generation volumes of $40 million as a result of low water inflows, partially offset byand an increase in energy purchases at higher spot prices of $45 million; andprices;
Eletropaulo decreased $5$29 million due to higher fixed costs of $53$39 million, including higher payroll and pension expense, as well as higher depreciation and unfavorable impact of foreign exchange, partially offset by $59$15 million of higher rates as a result of the July 20132014 tariff adjustmentadjustment; and volume.
These decreases were partially offset by:
Sul increaseddecreased by $13$26 million driven by lower volume and higher volumes from warmer weather of $10 million.fixed costs.
Adjusted Operating Margin decreased $883 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increasedecreased $3784 million, asdue to the decrease of $883 million in Adjusted Operating Margin as described above was offset by the reversal of a loss contingency related to interest expense of $47 million at Sul that is no longer considered probable.above.

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Including the unfavorable impact of foreign currency translation of $83 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 increased $75decreased $187 million, or 15%23%. This performance was driven primarily by the following businesses and key operating drivers:
Tietê increased $74decreased $129 million, driven by a net impact of $142 million related to higher sales in the spot market, partially offset by lower contracted volumes of energy sold to Eletropaulo, and unfavorable foreign exchange rates of $61 million;
Eletropaulo increased $24 million, driven by higher tariffs and volume of $99 million, partially offset by unfavorable foreign exchange rates of $17 million and the net impact of $61 million of lower hydrology which led to lower generation and an increase in energy purchases at higher fixed costs of $56 million; and
Sul increased $23 million, due to higher volume of $35 million,prices, partially offset by higher fixed cost expensespot sales in first half of $3 million mainly related to services,2014 due to the stormy weather, and unfavorable foreign exchange rateslower contracted volumes of $5 million.
These increases were partially offset by:energy sold;
Uruguaiana decreased $46$48 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.operations;
Eletropaulo decreased $5 million, driven by higher fixed costs and depreciation of $103 million and unfavorable foreign exchange rates of $16 million, partially offset by higher tariffs and volume of $114 million; and
Sul decreased $3 million, due to higher fixed cost and depreciation expense of $14 million mainly driven by storm related maintenance costs, lower rates of $10 million due to the April 2013 tariff reset, and unfavorable foreign exchange rates of $4 million, partially offset by higher volume of $26 million.
Adjusted Operating Margin increased $24decreased $60 million primarily due to the drivers discussed above, adjusted for the impact of noncontrollingnon-controlling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.

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Adjusted PTC increased $64decreased $20 million, driven by the increasedecrease of the $24$60 million in Adjusted Operating Margin described above and higher interest rates and debt, partially offset by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million at Sul that is no longer considered probable, partially offset by higher interest expense, as a result of an increase in interest rates.probable.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change
 ($’s in millions) ($’s in millions)
Operating Margin $146
 $149
 $(3) -2 % $235
 $254
 $(19) -7 % $176
 $143
 $33
 23% $411
 $397
 $14
 4%
Noncontrolling Interests Adjustment 17
 12
     10
 31
     20
 14
     30
 45
    
Derivatives Adjustment (3) (1)     (2) (1)     —
 —
     (2) (1)    
Adjusted Operating Margin $126
 $136
 $(10) -7 % $223
 $222
 $1
 — % $156
 $129
 $27
 21% $379
 $351
 $28
 8%
Adjusted PTC $95
 $104
 $(9) -9 % $160
 $160
 $—
 0%
 $124
 $96
 $28
 29% $284
 $256
 $28
 11%
Including the unfavorable impact of currency translation of $1 million, operating margin for the three months ended JuneSeptember 30, 2014 decreased $3increased $33 million, or 2%23%. This performance was driven primarily by the following businesses and key operating drivers:
Dominican Republic increased $23 million, mainly related to the favorable impact of rates of $29 million due to lower fuel prices, higher PPA prices, and higher prices of gas sales to third parties; and
Panama decreased $8increased $12 million, driven by the Esti tunnel settlement agreement received during the second quarter of 2013 of $31 million, partially offset by a compensation from the government of Panama of $16$13 million related to spot purchases driven by dry hydrological conditions, as well as lower fixed costs of $7 million; and
El Salvador decreased $4 million, due primarily to higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $11 million, mainly related to higher sales due to higher generation of $15 million, as well as higher availability during Q2 2014 of $9 million, partially offset by lower volume of gas sales to third parties of $8 million and higher fuel prices of $5 million.conditions.
Adjusted Operating Margin decreaseincreased $10$27 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC decreaseincreased $928 million, driven by the decreaseincrease of $1027 million in Adjusted Operating Margin as described above.

39



Including the unfavorable impact of currency translation of $2$4 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $19increased $14 million, or 7%4%. This performance was driven primarily by the following businesses and key operating drivers:
Dominican Republic increased $59 million, mainly related to lower fuel costs of $31 million and higher PPA prices of $12 million, higher availability of $20 million and related lower maintenance expenses of $8 million, partially offset by lower gas sales to third parties of $11 million.
This increase was partially offset by:
Panama decreased $39$27 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $45$51 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of $23$36 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs during 2014 of $14$17 million; and
El Salvador decreased $18$15 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $36 million, mainly related to higher availability of $17 million, lower maintenance and other costs of $7 million and higher PPA prices of $12 million.
Mexico increased $5 million, mainly driven by higher availability.
Adjusted Operating Margin increased $1$28 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC remained flat,increased $28 million, driven by the increase of $1$28 million in Adjusted Operating Margin described above, partially offset by lower equity in earnings from the Trinidad business, which was sold in 2013.above.

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EMEA SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our EMEA SBU for the periods indicated:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change
 ($’s in millions) ($’s in millions)
Operating Margin $77
 $86
 $(9) -10 % $210
 $200
 $10
 5% $94
 $85
 $9
 11% $304
 $285
 $19
 7%
Noncontrolling Interests Adjustment 5
 5
     11
 11
     7
 6
     18
 17
    
Derivatives Adjustment (4) —
     (4) —
     4
 —
     —
 —
    
Adjusted Operating Margin $68
 $81
 $(13) -16 % $195
 $189
 $6
 3% $91
 $79
 $12
 15% $286
 $268
 $18
 7%
Adjusted PTC $73
 $72
 $1
 1 % $188
 $168
 $20
 12% $79
 $66
 $13
 20% $267
 $234
 $33
 14%
Including the neutral impact of foreign currency translation, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreasedincreased $9 million, or 10%11%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014;
Maritza (Bulgaria)in Bulgaria increased $8 million, driven by better availability of $5 million related to timing of scheduled outages and lower depreciation of $3 million; and
Ebute in Nigeria increased $6 million primarily due to fewer outages of $2 million and lower depreciation of $2 million.
These increases were partially offset by:
Kilroot in the United Kingdom (U.K.) decreased $12$17 million driven by lower availability related to higher scheduled outages.
This decrease was partially offset by:
Kilroot (United Kingdom "U.K.") increased $5 million driven by higherdispatch and rates of $6 million, including income from energy price hedges, and strengthening of the British Pound, partially offset by higher outages of $2$14 million.
Adjusted Operating Margin decreaseincreased $1312 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $113 million, as a result of the decreaseincrease of $1312 million in Adjusted Operating Margin described aboveabove.
Including the unfavorable impact of foreign currency translation of $1 million, operating margin for the nine months ended September 30, 2014 increased $19 million, or 7%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014;
Ebute increased $7 million due to fewer outages of $6 million and lower depreciation;
Kazakhstan increased $6 million driven by higher generation volumes and rates of $19 million, partially offset by unfavorable foreign exchange impact of $8 million; and
Wind businesses in the U.K. increased $4 million, driven by higher contributions from Sixpenny Wood, Yelvertoft and Drone Hill, which were sold in August 2014.
These results were partially offset by:
Kilroot decreased $10 million, driven by lower dispatch and higher outages of $19 million, partially offset by higher rates of $11 million, including income from energy price hedges, and favorable foreign exchange impact.
Adjusted Operating Margin increased $18 million due to the drivers above adjusted for non-controlling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $33 million, driven primarily by the increase of $18 million in Adjusted Operating Margin, as well as a reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Including the favorable impact of foreign currency translation of $1 million, operating margin for the six months ended June 30, 2014 increased $10 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:
Kilroot (U.K.) increased $6 million, driven by higher rates, including income from energy price hedges, favorable FX,AES, partially offset by lower dispatch and higher outages;
Wind businesses (U.K.) increased $4 million, driven primarily by new business generation from Sixpenny Wood and Yelvertoft which commenced commercial operation in July 2013 and higher generation from Drone Hill;

40



Kazakhstan increased $3 million driven by higher generation volumes and rates, partially offset by unfavorable foreign currency; and
Ballylumford (U.K.) increased $2 million, due to higher volumes, partially offset by higher fixed costs.
These results were partially offset by:
Maritza (Bulgaria) decreased $6 million, driven primarily by higher scheduled outages, partially offset by higher rates.
Adjusted Operating Margin increased $6 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $20 million, driven primarily by the increase of $6 million in Adjusted Operating Margin, as well as a reversal of a liability in Kazakhstan as described above, partially offset by lower equity in earnings from Turkey.
Asia SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Asia SBU for the periods indicated:
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change 2014 2013 $ Change % Change
 ($’s in millions) ($’s in millions)
Operating Margin $27
 $45
 $(18) -40 % $37
 $83
 $(46) -55 % $12
 $38
 $(26) -68 % $49
 $121
 $(72) -60 %
Noncontrolling Interests Adjustment 1
 3
     1
 5
     9
 2
     10
 7
    
Derivatives Adjustment —
 —
     —
 —
     —
 —
     —
 —
    
Adjusted Operating Margin $26
 $42
 $(16) -38 % $36
 $78
 $(42) -54 % $3
 $36
 $(33) -92 % $39
 $114
 $(75) -66 %
Adjusted PTC $23
 $40
 $(17) -43 % $31
 $71
 $(40) 56 % $2
 $30
 $(28) -93 % $33
 $101
 $(68) 67 %

43



Operating margin for the three months ended JuneSeptember 30, 2014 decreased by $1826 million, or 40%68%. This performance was driven primarily by the following businesses and key operating drivers:
Masinloc (Philippines)in the Philippines decreased by $17$23 million driven by lower plant availability and related maintenance of $14 million and the net impact of lower spot sales and lower price of spot purchases of $2$18 million; and
Kelanitissa (Sri Lanka)in Sri Lanka decreased by $5$6 million driven by the step down in the contracted PPA price.price and higher outages and maintenance costs.
Adjusted Operating Margin decreased by $16$33 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc.
Adjusted PTC decreased by $17$28 million, driven by the decrease of $16$33 million in Adjusted Operating Margin described above.above, partially offset by the impact of lower proportional interest expense at Masinloc, and OPGC higher equity earnings.
Operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased by $46$72 million, or 55%60%. This performance was driven primarily by the following businesses and key operating drivers:
Masinloc (Philippines)in the Philippines decreased by $41$64 million, driven by $20$33 million due to lower plant availability, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher fixed costs of $5 million primarily due to maintenance, and net impact of higher contract demand at lower prices and lower spot sales and lower price of spot purchases of $5$4 million; and
Kelanitissa (Sri Lanka)in Sri Lanka decreased by $10$16 million driven by the step down in the contracted PPA price.
Adjusted Operating Margin decreased by $42$75 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc.
Adjusted PTC decreased by $40$68 million, driven by the decrease of $42$75 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc due to a 2013 debt refinancing.and gains on foreign currency.
Key Trends and Uncertainties
During the remainder of 2014 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors, a combination of factors, (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2013 Form 10-K.
Regulatory
Ohio—As noted in Item 1. — Business - United States— US SBU — Dayton Power & Light Company of the 2013 Form 10-K, an order was issued by the Public Utilities Commission of Ohio ("PUCO") in September 2013 (the “ESP Order”), which states that DP&L’s next ESP begins January 1, 2014 and extends through May 31, 2017.
On March 19, 2014, the PUCO issued a second entry on rehearing ("Entry on Rehearing") which changes some terms of
the ESP order. The Entry on Rehearing shortens the time by which DP&L must divest its generation assets to no later than
January 1, 2016 from May 31, 2017 in the ESP Order. The Entry on Rehearing also terminates the potential extension of the
Service Stability Rider on April 30, 2017 instead of May 31, 2017. In addition, the Entry on Rehearing accelerates DP&L’s
phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016, compared to 10% in 2014, 40%
in 2015, 70% in 2016 and 100% in June 2017 in the ESP Order. Parties, including DP&L, have filed applications for rehearing
on this Commission Order, which were granted in the PUCO’s third entry on rehearing on May 7, 2014.
On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the deadline by which DP&L must divest
its generation assets to January 1, 2017. The Ohio Consumer's Counsel has filed an application for rehearing on this Order,
which was denied by the PUCO. On June 30, 2014, several intervening parties filed a joint motion to stay collection of the Service Stability Rider while appeals are pending. This motion to stay was denied by the PUCO. The Industrial Energy Users of Ohio and the Ohio Consumer's Counsel filed Notices of Appeal of various aspects of the ESP Order and Entries on Rehearing to the Ohio Supreme Court on August 29, 2014 and September 22, 2014, respectively. On September 19, 2014, DP&L filed a Notice of Cross-appeal of the accelerated phase-in of the competitive bidding structure.

44

In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets on or before May 31, 2017. DP&L amended its application on February 25, 2014 and again on May 23, 2014. On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications. Specifically, DP&L’s request to defer costs associated with the Ohio Valley Electric Corporation (OVEC) which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets. See Item 1. - — Business -— United States SBU -— Dayton Power & Light Company of the 2013 Form 10-K for further details of the ESP order and the filing to separate generation.
Philippines—In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, Energy Regulatory Commission ("ERC") declared the market prices from this period void and ordered the market operator to recalculate the prices for all market participants for November and December 2013 billing months. The recalculation of prices based on the load weighted average prices for the first nine months of 2013 resulted in an unfavorable adjustment of approximately $15 million to Masinloc spot sales. The ERC’s review of the motions for reconsideration filed by market participants including Masinloc is on-going. A secondary price cap was established for May and June 2014 and has been extended to mid-August,December, as a temporary measure to mitigate spot price impacts in the market. AtAs of this time the measure is expected to apply temporarilyhas not had a material impact on our business in 2014, in which case the impact may not be material.Philippines. However, if similar measures are implemented on a permanent basis, the impact could be material.
Dominican Republic— In August 2014, the Superintendence of Electricity (Sectoral Regulatory Body of the Electricity Sector), modified the rules for offering primary frequency regulation service, an ancillary service item. The former rules allocated the service to generators based on merit order and those which were the most flexible and could enter the system quickly generally satisfied the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by own source or through bilateral contracts with other generators who can offer the service, and any additional supply requirement must be allocated using the merit order process. As the AES businesses, Andres and Los Mina, were lower in the merit order they received a majority of the allocation under the former rules. The lower allocation of this service to these units under the new rules will have an impact of lowering the margin from frequency regulation which will be partially offset by higher energy dispatch.
Operational
Sensitivity to Dry Hydrological Conditions

Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Throughout 2013 and 2014, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in these markets. Low rainfall and water inflows caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. Some local forecasts suggest continued dry conditions for the remainder of 2014. Once rainfall and water inflows return to normal levels, high market prices and low generation could persist until reservoir levels are fully recovered.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and manages an Energythere is a mechanism called MRE (Energy Reallocation MechanismMechanism) created to share hydrological risk across all generators. If the system of hydroelectric generation facilities generates less than the assured energy of the system, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. We expect the system operator in Brazil to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 16 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices higher than historicalat high levels. During the first and second quarters of 2014, AES Tietê benefited from lower contract levels and captured spot sales at favorable prices. However, AES Tietê has higher contract obligations in the second half of 2014 and may needhas needed to fulfill some of these obligations with spot purchases, so itthey will be sensitive to generation output and spot prices for electricity during this period. Finally, if dry conditions persist in Brazil throughout 2014 and into the next rainy season, from NovemberDecember 2014 to April 2015, there is a risk that the

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government of Brazil could implement a rationing program in 2015, which could have a material adverse impact on our results of operations and cash flows.
In Panama, dry hydrological conditions continue to reduce generation output from hydroelectric facilities and have increased spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during the peak hours by approximately 300 MW, which contributed to water savings in the key hydroelectric dams and lower spot prices. AES Panama has had to purchase energy on the spot market to fulfill its contract obligations when its generation output is below its contract levels, and we expect this trend to continue for the remainder of the year. As authorized on March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70MW reduction in contracted capacity for the period

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2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016. Compensation payments recognized through September 30, 2014 were $36 million, of which $12 million are pending to be collected. AES owns 49% of AES Panama. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $26 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015.
Taxes
Chilean Tax Reform
On April 1,September 29, 2014, the Chilean government sent to Congress a bill proposingenacted comprehensive tax reforms. The proposed reforms would introducewhich introduced significant changes which, among others, include an increase in theto corporate income tax rate from 20% to 25% over a periodrates, modification of 4 years, the introduction of “Greenshareholder level income tax beginning in 2017, and new “green taxes” primarily over CO2 emissions and from 2017 a shareholder level tax on accrued profits rather than on actual dividends. The potential new legislation is being debatedalso beginning in Congress and could be subject to2017. See Note 17 — Income Taxes in Part I. Item 1. — Financial Statements of this Form 10-Q for further modification in the next several months. Should the bill be approved, the financial impact could be material.information.
Macroeconomic and Political
During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue.
Argentina — In Argentina, economic conditions are deteriorating, as measured by indicators such as non-receding inflation, diminishing foreign reserves, the potential for continued devaluation of the local currency, and a decline in economic growth. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At JuneSeptember 30, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 6 — Financing Receivables in Part I Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables. Although our businesses in Argentina have been able to access foreign currency for parts, equipment and equipmentfuel purchases and debt payments when needed, a further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets.
Argentina defaulted on its public debt in 2001, when it stopped making payments on about $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Argentina has expressed thatAlthough this situation remains unresolved, it will attempt to reach a satisfactory settlement agreement to unlock the current situation. This situation has not caused any significant changes that impact our current exposures other than those that are discussed above in regards to the macroeconomics within the country.
Bulgaria—Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned electricity public supplier and energy trading company. Maritza, a lignite-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by NEK. In November 2013, Maritza and NEK signed a rescheduling agreement for the overdue receivables as of November 12, 2013. Under the terms of the agreement, NEK paid $70 million of the overdue receivables and agreed to pay the remaining receivables in 13 equal monthly installments beginning December 2013. NEK has made payments according to the schedule through JulySeptember 2014. As of JuneSeptember 30, 2014, Maritza had outstanding receivables of $226 million, representing $43$50 million of current receivables, $30$14 million of the rescheduled receivables not yet due, $85$74 million of receivables overdue by less than 90 days and $69$88 million of receivables overdue by more than 90 days. On July 31, 2014 Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD

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(MMI), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17.3$17 million through an offset of payables due by Maritza to MMI. Additionally, NEK has agreed to four additional monthly installments totaling $27.6$28 million to be paid equally from August to November, 2014. Maritza has also received payments on outstanding receivables of $14.5 million subsequent to June 30, 2014 which were not under the tripartite agreement. Although Maritza continued to collect overdue receivables during the secondthird quarter of 2014 and thereafter, there continue to be risks associated with collections, which could result in a write-off of the remaining receivables and/or liquidity problems which could impact Maritza's ability to meet its obligations, if the situation around collections were to deteriorate significantly.
In May and June 2014, Bulgaria’s State Energy and Water Regulatory Commission (SEWRC) issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza,

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which could further impactimpacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. It is unclear whether NEK will abide by its obligations underHowever, SEWRC confirmed that until such negotiations conclude, the PPA or objectis in full force and effect and NEK has not objected to Maritza's invoices going forward.invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria.Bulgaria with the first hearing scheduled for the beginning of 2015. In addition, SEWRC announced that it has asked the Directorate-General for Competition of the European Commission (DG Comp) to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date.
On July 24, 2014, the Government of Bulgaria formally resigned.resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections are scheduled forwere held on October 5, 2014 to put2014. Eight political parties were elected and are currently discussing the formation of a new government in place. Installation of the new governmentwhich is expected to allow the negotiations to continue in a productive manner. Meanwhile the Caretaker Government requested and received the resignations of the former Chairman and two commissioners of the Regulator. The new leadership approved an end-consumer energy price increase of approximately 10% effective October 1, 2014, which is expected to slightly improve NEK's liquidity. The Caretaker Government also established an Energy Board, which is consultative body comprised of members who have an interest in the energy sector, with the objective to discuss and propose measures to be taken for stabilization of the energy sector. Maritza is a member of the Energy Board.
As a result of any of the foregoing events (including failure by NEK to honor its obligations under the PPA for any reason), we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value (including, without limitation, the value of receivables listed above) and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. For further information about the risks associated with the Company's investment in Maritza, see the following items in the Company's 2013 Form 10-K: Item 1— Business - EMEA; Item 1A. — Risk Factors of the 2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and Item 7: Management's Discussion & Analysis - Key Risks and Uncertainties.Uncertainties. See Note 8 — Debt included in Part I Item 1. — Financial Statements of this Form 10-Q for further information on current existing debt defaults. Further, Maritza is in litigation related to construction delays and related matters. For further information on the litigation see Part II Item 1. — Legal Proceedings.
Maritza will take all actions necessary to protect its interests, whether through negotiated agreement with NEK or through enforcement of its rights under the PPA. In addition, if necessary, Maritza will defend the PPA in any assessment or proceeding that may be initiated by DG Comp in response to SEWRC's request. As such, as of JuneSeptember 30, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.4$1.3 billion and total debt of $797$720 million, and Kavarna, which were $280$256 million and total debt of $190$176 million. Therefore, there is no reason to believemanagement believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014.
Puerto Rico— Our subsidiary in Puerto Rico has a long-term PPA with the Puerto Rico Electric Power Authority (“PREPA”), a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers. As a result of macroeconomic challenges in the country, including a seven-year recession, PREPA faces economic challenges including, but not limited to reliance on high cost fuel oil, decline in electricity sales, high customer power rates, high operating costs, past due accounts receivables from government institutions, and very low liquidity along with challenges obtaining financing due to the recent downgrades, and has struggled to honor its payment obligations to electricity generators on a timely basis. As a result, AES Puerto Rico's receivables balance has increased toas of September 30, 2014 is $95 million, outstanding as of June 30, 2014, of which $27$33 million is overdue and days sales outstanding from PREPA has deteriorated, which has caused our business to start to be delayed in our payments to suppliers. Subsequent to JuneSeptember 30, 2014, the overdue receivables of $27$30 million have been collected.
In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and it's public sector companies (PREPA included) to below investment grade. On June 28, 2014, the Governor of Puerto Rico signed into law the Recovery Act, which allows public corporations to adjust their debts in the interest of all creditors, and establishes procedures for the orderly enforcement. With the recent passing of the Recovery Act, the ratings were further reduced. S&PThe downgrade on PREPA has yet to lowerhad a direct impact on AES Puerto Rico's bonds, except for Moody's which rates the Commonwealth's rating butbonds above the state-owned corporation given AES Puerto Rico is expected to do so in the near term.lowest cost producer of electricity. We believe that AES Puerto Rico’s unique position as the lowest cost energy producer and cost-effective alternative for PREPA relative to fuel oil generated power, positions the business well and reduces the probability of negative impacts from a potential PREPA restructuring process. However there can be no assurance as to the final terms of any restructuring or potential impacts on AES Puerto Rico.
If AES Puerto Rico fails to receive payment in accordance with the terms of the PPA with PREPA, its liquidity issues could worsen, which could further impact AES Puerto Rico's ability to meet its obligations. See Item 1A. — Risk Factors of the

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2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and "We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations." As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
Our Puerto Rico business will take all actions necessary to protect its interests, whether through negotiated agreement with PREPA or through enforcement of its rights under the PPA. In October 2014, the Parent Company reached an agreement with an investor in AES Puerto Rico's preferred shares to retire the investment at a fixed redemption value of $52 million. The redemption is expected to be completed by the end of 2014. As the events pertaining to the Recovery Act continue to

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unfold, we concluded that there is no indicator of an impairment of the long-lived assets in Puerto Rico, which were $620$635 million and total debt of $584 million, and there is no reason to believe$594 million. Therefore, management believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014.
If global economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.
Impairments

Goodwill — Since its annual goodwill impairment test in the fourth quarter of 2013, the Company has been monitoring three reporting units, DP&L, DPLER and Buffalo Gap, as “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. In the first quarter of 2014, the Company recognized a full goodwill impairment of $136 million at DPLER and a goodwill impairment of $18 million at Buffalo Gap. The Company continues to monitor the remaining goodwill of $10 million at Buffalo Gap and the $316 million goodwill at DP&L. It is possible that the Company may incur goodwill impairment at DP&L, Buffalo Gap or any other reporting unit in future periods if certain events, such as, adverse changes in their business or operating environments occur.
Environmental
The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts) and certain air emissions, such as SOsulfur dioxide (SO2), NOnitrogen oxides (NOx), particulate matter (PM)and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. —- Risk Factors, “Our“Our businesses are subject to stringent environmental laws and regulations,,” “Our“Our businesses are subject to enforcement initiatives from environmental regulatory agencies,,” and “Regulators,“Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows”flows” set forth in the Company’s Form 10-K for the year ended December 31, 2013.2013. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. —- Business —- Regulatory Matters —- Environmental and Land Use Regulations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Item 2. —- Management's Discussion and Analysis of Financial Condition and Results of Operations —- Key Trends and Uncertainties —- Regulatory —- Environmental of the Company'sCompany’s Quarterly ReportReports on Form 10-Q for the fiscal quarterquarters ended March 31, 2014 and June 30, 2014.
UpdateTax on Greenhouse GasCarbon and Other Emissions Regulationsin Chile
In September 2014, the government of Chile enacted a carbon tax of $5.00 per ton of CO2, as well as taxes on emissions of PM, SO2 and NOx. The United States Environmental Protection Agency (“EPA”) issued proposed rules establishing greenhouse gas (“GHG”) performance standardsamount of the annual tax on PM, SO2 and NOx depends on volume and geographic location of the emissions, among other factors. This tax will be paid annually for existing power plants under Clean Air Act Section 111(d) on June 2, 2014. Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targetsin the previous year, beginning in 2020, with expected total U.S. power section2018 for emissions reductionin 2017. The financial impact to the Company of 30% from 2005 levels by 2030. The proposed rule requires states to submit

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implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances. The proposed rule will be subject to a public comment process during the course of this year, after which time EPA is expected to finalize it by President Obama’s June 1, 2015 deadline. Among other things, the Company's U.S.-based businessesthese taxes could be required to make efficiency improvements to existing facilities. However, it is too soon to determine what the rule, and the corresponding state implementation plans affecting the Company’s U.S.-based businesses, will require once they are finalized, whether they will survive judicial and other challenges, and if so, whether and when the rule and the corresponding state implementations plan would materially impact the Company’s business, operations or financial condition.
In addition,material in October 2013, the U.S. Supreme Court granted certiorari for several cases that address EPA’s authority to issue GHG Prevention of Significant Deterioration (“PSD”) permits under Section 165 of the CAA. In June 2014, the U.S. Supreme Court ruled that EPA had exceeded its statutory authority in issuing the so-called “Tailoring Rule” under Section 165 of the CAA by regulating all sources that emitted GHGs. However, the U.S. Supreme Court also held that EPA could impose GHG Best Achievable Control Technology (“BACT”) requirements for sources already required to implement under PSD for other pollutants. Therefore, if future modifications to the Company's U.S.-based businesses' sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the U.S. Supreme Court’s ruling and GHG BACT requirements applicable to the operation of the Company's U.S.-based businesses cannot be determined at this time as these businesses are not required to implement BACT until they construct a new major source or make a major modification of an existing major source. However, the cost of compliance could be material.
Update on MATS
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — MATS in the Company's Form 10-K for the year ended December 31, 2013, several lawsuits challenging the Mercury Air Toxics Standards (“MATS”) were filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). On April 15, 2014, a three-judge panel of the D.C. Circuit denied the challenges. Twenty-three states and certain industry groups have petitioned the United States Supreme Court to review the decision. We currently cannot predict whether the petition will be granted.
On June 20, 2014, IPL contemporaneously filed a waiver request/alternative complaint with the Federal Energy Regulatory Commission ("FERC") requesting a waiver that will allow IPL to keep 216 MW of reliable capacity available at its Eagle Valley generating station from June 1, 2015 through April 15, 2016. Both of these filings request that the FERC either waive or reform certain requirements of the Midcontinent Independent System Operator, Inc. market tariff for failing to address the specific circumstances resulting from compliance with MATS.
Update on Cooling Water Intake Structures Standards
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, the Company’s facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. On May 19, 2014, the EPA announced its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. These standards require subject facilities that utilize at least 25% of the withdrawn water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include public input as part of permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.periods.

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Update on Environmental Wastewater Requirements
As discussed in Item 1. Business - United States Environmental and Land Use Regulations - Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, certainDP&L is appealing various aspects of the Company’s U.S.-based businesses are subject toa National Pollutant Discharge Elimination System (“NPDES”) permit for J.M. Stuart Station issued by the Ohio EPA. NPDES permits that regulate specific industrial waste waterwastewater and storm water discharges to the watersinto a water of the United States under the FederalU.S. Clean Water Act (“CWA”). In June 2014, the EPA alongAct. It is believed that compliance with the U.S. Army Corpspermit as written will require capital expenses that will be material to DP&L. The cost of Engineers issuedcompliance and the timing of such costs is uncertain and may vary considerably depending on a proposed rule definingcompliance plan that would need to be developed, the waterstype of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the United States. This rulemakingfinal permit to the Environmental Review Appeals Commission and a hearing has been scheduled for March 2015. The compliance schedule in the potentialfinal permit has been modified to impact all programs underaccommodate the CWA. Expansion of regulated waterways is possible based on initial reviewtiming of the proposal, which may impact several permitting programs. Although we cannot at this time determine the timing or impacthearing. The outcome of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.such appeal is uncertain.
Update on the CSAPR
As furtherAlso as discussed in Item 1. 1. Business —- United States Environmental and Land Use Regulations — CAIR and CSAPR - Water Dischargesin the Company's Form 10-K for the year ended December 31, 2013, in responsethe Indiana Department of Environmental Management (“IDEM”) issued NPDES permits to the D.C. Circuit’s striking down muchIPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. These permits set new water quality-based levels of acceptable metal effluent water discharges for the EPA’s Clean Air Interstate Rule (“CAIR”)Petersburg and remanding itHarding Street facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance with the new metal effluent limitations required by October 2015. IPL received an extension to the EPA, the EPA issued a new rule in July 2011 titled “Federal Implementation Planscompliance deadline through September 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO2 and NOx emissions from covered sources, such as power plants, in certain states in which subsidiaries of the Company operate. Once fully implemented (originally planned for 2014), the rule would requiredetermine what operational changes and/or additional SO2 emission reductions of 73% and additional NOx reductions of 54% from 2005 levels. The CSAPR would be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPAequipment will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, the EPA would issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.
Upon petitions for review filed by many states, utilities and other affected parties, the D.C. Circuit vacated the CSAPR in August 2012 and required the EPA to continue administering CAIR pending the promulgation of a valid replacement to the CSAPR. Prior to this decision, the D.C. Circuit had granted a stay of the CSAPR. On April 29, 2014, the United States Supreme Court upheld the CSAPR, reversing the D.C. Circuit Court’s decision to vacate the CSAPR.
It is difficult to predict the steps that will follow this ruling. There remain numerous challenges to the CSAPR that must be addressed, some of which could again result in delay or invalidation of the CSAPR. On June 26, 2014, EPA filed a motion in the D.C. Circuit requesting that the court lift the stay of the CSAPR. EPA also requested that the court extend CSAPR’s compliance deadlines by three years, so that the Phase 1 emissions budgets that were to begin in 2012 would now apply starting in 2015, and the Phase 2 emissions that were to begin in 2014 would apply starting in 2017. The multiple parties to the litigation have filed oppositions to EPA’s motion to lift the stay and all parties have filed motions to govern further proceedings. If the D.C. Circuit grants EPA’s motion, the Company anticipates an increase in capital costs and other expenditures and operational restrictions that would be required to comply with the new limitations. On August 15, 2014, IPL announced its intent to file plans with the IURC to refuel Unit 7 at Harding Street from coal-fired to natural gas. This conversion is part of IPL's overall wastewater compliance plan for its power plants. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. IPL is seeking approval for a reinstated CSAPR. AtCertificate of Public Convenience and Necessity (CPCN) to install and operate wastewater treatment technologies at its Petersburg and Harding Street plants. If approved, IPL will invest $332 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. IPL expects to recover through its environmental rate adjustment mechanism, operating or capital expenditures related to compliance with these NPDES permit requirements. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact that such rules would haveof these permit requirements on the Company; they could have a material impact on the Company's business,our consolidated results of operations, cash flows, or financial condition, and results of operations.
IPL Unit Retirement and Replacement Generation
As discussed in Item 1. Business — United States Environmental and Land Use Regulations — Unit Retirement and Replacement Generation in the Company's Form 10-K for the year ended December 31, 2013, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to build a 550 MW to 725 MW combined cycle gas turbine (“CCGT”) at its Eagle Valley generating station and to refuel its Harding Street generating station Units 5 and 6 from coal to natural gas (about 100MW each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $626 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that we are allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGTbut it is expected to be placed into service in April 2017, and the refueling project is expected to be completed in early 2016. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service.material.


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Capital Resources and Liquidity
Overview
As of JuneSeptember 30, 2014, the Company had unrestricted cash and cash equivalents of $1.51.7 billion, of which approximately $15229 million was held at the Parent Company and qualified holding companies, and approximatelycompanies. The Company had $424686 million was held in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.0 billion967 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.915.7 billion and $5.85.3 billion, respectively. Of the approximately $2.12.3 billion of our current non-recourse debt, $1.1$1.4 billion was presented as such because it is due in the next twelve months and $1.00.9 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated

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long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility and floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.915.7 billion of total non-recourse debt outstanding as of JuneSeptember 30, 2014, approximately $3.94.1 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At JuneSeptember 30, 2014, the Parent Company had provided outstanding financial and performance-related guarantees, indemnities or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $620 million$1.0 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At JuneSeptember 30, 2014, we had $1 million in letters of credit outstanding, provided under our senior secured credit facility, and $10297 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended JuneSeptember 30, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has

47



near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.
As of JuneSeptember 30, 2014, the Company had approximately $258246 million and $3924 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond JuneSeptember 30, 2014, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6 — Financing Receivables included in Part I Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2013 Form 10-K for further information.
Consolidated Cash Flows
During the sixnine months ended JuneSeptember 30, 2014,, cash and cash equivalents decreaseincreased $127$28 million to $1.5$1.7 billion. The decreaseincrease in cash and cash equivalents was due to $453 million1.2 billion of cash provided by operating activities, $391364 million of cash used

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in investing activities, $250844 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $1455 million and a $75 million decrease in cash of discontinued and held-for-sale businesses.
Operating Activities — Net cash provided by operating activities decreased $732824 million to $453 million during the six months endedJune 30, 2014 compared to $1.2 billion during the sixnine months ended JuneSeptember 30, 2014 compared to $2 billion during the nine months endedSeptember 30, 2013. This performance was driven primarily by the following SBUs and key operating activities:
Brazil — a decrease of $505 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes;
MCAC — a decrease of $179 million at our generation businesses primarily due to higher working capital requirements; and
EMEA — a decrease of $94 million primarily due to higher working capital requirements.
OperatingNet cash flow forprovided by operating activities was $1.2 billion during the sixnine months ended JuneSeptember 30, 2014. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, impairment expenses and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $1 billion in operating assets and liabilities. This net use of cash forwithin operating activities of $1 billion was primarily due to the following:
an increase of $316494 million in accounts receivable primarily related to higher sales at Eletropaulo, Sul and Alicura and lower collections at Maritza;
an increase of $439 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs;
an increase of $312 million in accounts receivable primarily related to higher sales at Sul, Alicura and Gener, return of operations at Uruguaiana in March 2014 and lower collections at Maritza;
a decrease of $194 million in accounts payable and other current liabilities primarily at Eletropaulo relating to a decrease in regulatory liabilities;
a decrease of $176239 million in net income tax and other tax payables primarily related to payments of income taxes exceeding accruals for the 2014 tax liability.liability; partially offset by
an increase of $319 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by reduced pension contributions at IPL and payments for share-based compensation issuance tax and derivative termination at the Parent Company.
Net cash provided by operating activities was $1.22.0 billion during the sixnine months ended JuneSeptember 30, 2013. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $310255 million in operating assets and liabilities. This net use of cash forwithin operating activities of $310$255 million was primarily due to:
a decrease of $252$578 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and a decrease in value added taxes payables due to the lower tariff in 2013 andas well as at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision;
an increase of $147$149 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs;
partially offset by
a decrease of $134$403 million in net income taxprepaid expenses and other tax payablescurrent assets primarily from payment of income taxes exceeding accrualsdue to a decrease in current regulatory assets, for the tax liability on 2013 income, partially offset by an accrualrecovery of indirect taxes in Brazil; partially offset by
prior-period tariff cycle energy purchases and transportation costs at Eletropaulo and Sul; and
a decrease of $191$135 million in accounts receivable primarily duerelated to lower tariffs in 2013 at Eletropaulo and higher collections combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.

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The net decrease of cash flows from operating activities of $732 million for the six months endedJune 30, 2014 compared to the six months endedJune 30, 2013 was primarily the result of the following:
Brazil — a decrease of $442 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes and interest on debt.
US — a decrease of $160 million primarily due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating results and higher working capital requirements at DPL.
MCAC — a decrease of $154 million at our generation businesses primarily due to higher working capital requirements.
Investing Activities — Net cash used in investing activities was $391364 million during the sixnine months ended JuneSeptember 30, 2014 primarily attributable to the following:
Capital expenditures of $908 million1.4 billion consisting of $536$789 million of growth capital expenditures and $372$600 million of maintenance and environmental capital expenditures. Growth capital expenditures primarily included amounts at Gener of $250$303 million, Eletropaulo of $83$125 million,Vietnam Mong Duong of $45$72 million, Jordan of $71 million, IPL of $61 million and Jordan $38Sul of $35 million. Maintenance and environmental capital expenditures primarily included amounts at IPL of $105$178 million, Eletropaulo of $42$73 million, Tietê of $40$64 million, Gener of $50 million, DPL of $48 million and DPLSul of $32 million.$41 million;
Acquisitions, net of cash acquired of $728 million consisted of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 7 — Investment in and Advances to Affiliates in Item 1. — Financial Statements of this Form 10-Q for further information. These amounts wereinformation; partially offset by
Proceeds from the sale of businesses of $890 million with$1.7 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $443 million for the sale of 45% of our equity interest in Masinloc, $179 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and $160the United States and $156 million from the sale of our businessesbusiness in Cameroon,Cameroon; and

51



Decreases in restricted cash, debt service reserves and other assets of $162 million including amounts at the USParent Company of $66 million, Maritza of $44 million and India; and
SalesAlto Maipo of short-term investments, net of purchases of $273 million primarily in Brazil.$37 million.
Net cash used in investing activities was $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:
Capital expenditures of $866 million$1.3 billion consisting of $454$690 million of growth capital expenditures and $412$640 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $138$188 million, Gener of $81$166 million, Jordan of $54$95 million, Sul of $44$57 million, Sixpenny WoodDPL of $22$28 million, Mong Duong of $19$27 million, Yelvertoft of $20 million, Kribi of $17 million and YelvertoftAltai of $19$16 million. Maintenance and environmental capital expenditures included amounts at IPALCOIPL of $87$164 million, Eletropaulo of $72$103 million, DPL of $63 million, Gener of $47$61 million, DPLTietê of $46$53 million, Sul of $39$50 million, Altai of $21 million and Itabo of $15 million;
Purchase of short-term investments, net of sales of $263 million including amounts at Eletropaulo of $212 million, Sul of $32 million and Tietê of $30$29 million; partially offset by
Proceeds from the sale of business, net of cash sold of $135$167 million including $113 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.

Net cash used in investing activities decreased $315903 million to $391364 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in investing activities of $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This net decrease was primarily due to an increase in proceeds from the sale of business, net of cash sold of $1.5 billion, a decrease in purchases of short-term investments, net of sales of $343212 million, partially offset by an increase in acquisitions of $725 million.
Financing Activities — Net cash used in financing activities was $250844 million during the sixnine months ended JuneSeptember 30, 2014. This was primarily attributable to the following:
Payments for financed capital expenditures of $312 million, primarily at Mong Duong with $272 million in payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to minority interests of $197 million primarily at Tietê with $109 million; and
Repayments of recourse and non-recourse debt of $3.03.7 billion including amounts at the Parent Company of $1.7$2 billion, Gener of $853$905 million, Tietê of $132 million, Maritza of $65 million, Shady Point of $52 million, Puerto Rico of $51 million and Puerto Rico$114 million related to the UK Wind sale;
Distributions to noncontrolling interests of $42$377 million including amounts at Tietê of $188 million, Brasiliana Energia of $65 million, Gener of $35 million and Buffalo Gap of $33 million;
Payments for financed capital expenditures of $360 million primarily at Mong Duong of $272 million; partially offset by
Issuances of recourse and non-recourse debt of $3.23.8 billion, including new issuances at the Parent Company of $1.5 billion, Gener of $700 million, Mong Duong of $298 million, Eletropaulo of $253 million, Cochrane of $173 million, IPL of $130 million and Tietê of $129 million; and a draw down under construction loan facility at Mong Duong of $272 million.
Net cash used in financing activities was $799635 million during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:

49



Payments for financed capital expenditures of $257 million, primarily at Mong Duong for payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $211 million included amounts at Tietê of $98 million, Brasiliana of $34 million, Buffalo Gap of $25 million, and Gener of $18 million;
Payments for financing fees of $127 million included amounts at Cochrane of $41 million, Eletropaulo of $25 million, and Mong Duong of $13 million; and
Repayments of recourse and non-recourse debt of $3.4$3.5 billion primarilyincluded amounts at the Parent Company of $1.2 billion, Masinloc of $546 million, DPL of $425 million, Tietê of $396 million, El Salvador of $301 million, IPL of $110 million, Warrior Run of $87$93 million, Puerto Rico of $52$65 million, Maritza of $57 million, Sonel of $46 million and Sul of $37$40 million;
Payments for financed capital expenditures of $436 million, primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $385 million included amounts at Tietê of $154 million, Brasiliana Energia of $96 million, Gener of $39 million and MaritzaBuffalo Gap of $29$19 million;
Payments for financing fees of $148 million included amounts at Cochrane of $42 million, Eletropaulo of $25 million, Mong Duong of $20 million and the Parent Company of $17 million; partially offset by
Issuances of recourse and non-recourse debt of $3.1$3.8 billion,, including amounts at the Parent Company for $750 million, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $339 million, El Salvador of $310 million, Mong Duong of $210 million, DPL of $200 million, IPL of $170 million, Sul of $150 million, Jordan of $138 million, Cochrane of $82$120 million,Warrior Run of $74 million and Kribi of $63 million; and
Contributions from noncontrolling interests of $157 million including amounts at Mong Duong of $55 million, Alto Maipo of $50 million and JordanCochrane of $61$34 million.
Net cash used in financing activities decreasedincreased $549209 million to $250844 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in financing activities of $799635 million during the sixnine months ended JuneSeptember 30, 2013. This net decreaseincrease was primarily due to a decreasean increase in the repayments of recourse and non-recourse debt of $363 million and an increase in the issuance of recourse and non-recourse debt of $102162 million.

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Proportional Free Cash Flow (a non-GAAP measure)
We define Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below.
We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1. Business— US SBU — IPALCO — Environmental Matters in the 2013 Form 10-K for details of these investments.
The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the Company.
The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies

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 Three months ended June 30, Six months ended June 30, Three months ended September 30, Nine months ended September 30,
 2014 2013 2014 2013 2014 2013 2014 2013
 (in millions) (in millions)
Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below:                
Maintenance Capital Expenditures $152
 $174
 $289
 $360
 $169
 $166
 $458
 $526
Environmental Capital Expenditures 77
 42
 111
 73
 62
 72
 172
 145
Growth Capital Expenditures 414
 354
 820
 690
 298
 405
 1,119
 1,095
Total Capital Expenditures $643
 $570
 $1,220
 $1,123
 $529
 $643
 $1,749
 $1,766
Consolidated                
Net cash provided by operating activities $232
 $567
 $453
 $1,185
 $763
 $855
 $1,216
 $2,040
Less: Maintenance Capital Expenditures, net of reinsurance proceeds 152
 174
 289
 360
 169
 166
 458
 526
Less: Non-recoverable Environmental Capital Expenditures 25
 26
 36
 47
 16
 22
 52
 69
Free Cash Flow $55
 $367
 $128
 $778
 $578
 $667
 $706
 $1,445
Reconciliation of Proportional Operating Cash Flow                
Net cash provided by operating activities $232
 $567
 $453
 $1,185
 $763
 $855
 $1,216
 $2,040
Less: Proportional Adjustment Factor (1)
 64
 263
 44
 367
 208
 327
 251
 694
Proportional Operating Cash Flow $168
 $304
 $409
 $818
 $555
 $528
 $965
 $1,346
Proportional                
Proportional Operating Cash Flow $168
 $304
 $409
 $818
 $555
 $528
 $965
 $1,346
Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1)
 102
 121
 206
 258
 116
 114
 322
 372
Less: Proportional Non-recoverable Environmental Capital Expenditures (1)
 19
 18
 27
 34
 12
 17
 39
 51
Proportional Free Cash Flow $47
 $165
 $176
 $526
 $427
 $397
 $604
 $923
(1) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by non-controlling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 70% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $30 (or $100 x 30%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to non-controlling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur.
Proportional Free Cash Flow for the three months ended JuneSeptember 30, 2014 compared to the three months ended JuneSeptember 30, 2013 increased $30 million, driven by higher Proportional Operating Cash Flow and lower Proportional Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by increases from the following SBUs and key operating drivers:
US — driven by higher operating cash flow at the US Utilities driven by lower working capital requirements and higher earnings; and
Brazil — driven by Sul due to higher collections, partially offset by higher energy purchases and higher tax payments.
These increases were partially offset by decreases at:

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Asia — driven by Masinloc due to lower earnings and higher working capital requirements;
EMEA — driven by lower results for Wind entities driven by sale of UK Wind assets, sold in August 2014, and lower collections at Kavarna in Bulgaria as well as Kilroot in the U.K. driven by lower earnings;
MCAC — driven by higher working capital requirements as a result of lower collections and timing of inventory in the Dominican Republic.
Proportional Free Cash Flow for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 decreased $118$319 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance and Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by decreasesincreases from the following SBUs and key operating drivers:
MCAC — due todriven by higher working capital requirements in the Dominican Republic;Republic and Panama;
Brazil — driven by higher pricesprice of energy purchases as well asand higher taxes and interest on debt at Eletropaulo and Sul.Sul; and
These decreases were partially offset by an increase at:
CorpEMEA — driven by lower interest payments.
Proportional Free Cash Flow for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 decreased $350 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance Capital Expenditures. This performance was driven primarily by decreases from the following SBUs and key operating drivers:
Brazil — driven by higher prices of energy purchases as well as higher taxes and interest on debt at Eletropaulo and Sul;
MCAC — due to higher working capital requirements in the Dominican Republic; and
US — due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating resultsmargins and higher working capital requirementsin the U.K. and lower collections at DPL, partially offset by lower proportional maintenance capital expenditures.Maritza and Kavarna in Bulgaria.
Parent Company Liquidity
The following discussion of Parent Company Liquidity has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP as a measure of liquidity. Cash and cash equivalents are disclosed in the condensed consolidated statements of cash flows. Parent Company Liquidity may differ from similarly titled measures used by other companies.
The principal sources of liquidity at the Parent Company level are:

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dividends and other distributions from our subsidiaries, including refinancing proceeds;
proceeds from debt and equity financings at the Parent Company level, including availability under our credit facilities; and
proceeds from asset sales.
Cash requirements at the Parent Company level are primarily to fund:
interest;
principal repayments of debt;
acquisitions;
construction commitments;
other equity commitments;
common stock repurchases;
taxes;
Parent Company overhead and development costs; and
dividends on common stock.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at the periods indicated as follows:
Parent Company Liquidity June 30, 2014 December 31, 2013 September 30, 2014 December 31, 2013
 (in millions) (in millions)
Consolidated cash and cash equivalents $1,515
 $1,642
 $1,670
 $1,642
Less: Cash and cash equivalents at subsidiaries 1,500
 1,510
 1,441
 1,510
Parent and qualified holding companies’ cash and cash equivalents 15
 132
 229
 132
Commitments under Parent credit facilities 800
 800
 800
 800
Less: Borrowings under the credit facilities (120) —
Less: Letters of credit under the credit facilities (1) (1) (1) (1)
Borrowings available under Parent credit facilities 679
 799
 799
 799
Total Parent Company Liquidity $694
 $931
 $1,028
 $931

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The Company paid a dividend of $0.05 per share to its common stockholders during the three months ended JuneSeptember 30, 2014. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends.
While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Considerations in this Item 2), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors “The, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.otherwise.” of the Company’s 2013 Form 10-K.
Various debt instruments at the Parent Company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:

limitations on other indebtedness, liens, investments and guarantees;
limitations on dividends, stock repurchases and other equity transactions;
restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;
maintenance of certain financial ratios; and

52



financial and other reporting requirements.
As of JuneSeptember 30, 2014, the Parent Company was in compliance with these covenants.
Non-Recourse Debt
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;
causing us to record a loss in the event the lender forecloses on the assets; and
triggering defaults in our outstanding debt at the Parent Company.
For example, our senior secured credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.12.3 billion. The portion of current debt related to such defaults was $1.00.9 billion at JuneSeptember 30, 2014, all of which was non-recourse debt related to two subsidiaries — Maritza and Kavarna.
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of JuneSeptember 30, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of JuneSeptember 30, 2014, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.

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Critical Accounting Policies and Estimates
The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in our 2013 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2013 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policiesthese remain the Company’sas critical accounting policies as of and for the sixnine months ended JuneSeptember 30, 2014.
During the third quarter of 2014, the following additional critical accounting estimate was employed with respect to the Company's sales of noncontrolling interests:
Sales of Noncontrolling Interests
The accounting for a sale of noncontrolling interests under the accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders’ equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders’ equity. In-substance real estate is comprised of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates previously disclosed in our 2013 Form 10-K for impairments and fair value.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
Our generation and utility businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between

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our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
These disclosures set forth in this Item 3 are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2013 Form 10-K.
Commodity Price Risk
Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an

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un-hedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.
When hedging the output of our generation assets, we utilize contract strategies that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk.
AES businesses will see changes in variable margin performance as global commodity prices shift. For the remainder of 2014, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $5 million for natural gas, $5 million for oil and less than $5 million for coal. Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. OffsetsExposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.
In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during some periods.
In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets.assets which can be an expensive cap depending on fuel pricing at the time required. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia, we

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operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.
In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.
In the MCAC SBU, our businesses have commodity exposure on un-hedged volumes. Panama is largelyhighly contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.

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In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are un-hedged, the commodity risk at our Kilroot business is to the clean dark spread — the difference between electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, the regulator has the right to terminate the contract, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business.
In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume soldor shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.
Foreign Exchange Rate Risk
In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, KazakhstaniKazakhstan Tenge, Mexican Peso and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.
We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, British Pound, Brazilian Real, Colombian Peso, Euro and Kazakhstan Tenge. As of JuneSeptember 30, 2014, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro and Kazakhstan Tenge relative to the U.S. Dollar are projected to be reduced by approximately $5 million, $5 million, $5 million, $5 million, less than $5 million and $5 million respectively,for each currency for the remainder of 2014. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2014 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements.
Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-

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recoursenon-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of JuneSeptember 30, 2014, the portfolio’s pretax earnings exposure for the remainder of 2014 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $10 million based on the impact of a one time, 100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”)CEO and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our

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disclosure controls and procedures were effective as of JuneSeptember 30, 2014 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Controls over Financial Reporting
ThereOn May 14, 2013, The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We have reviewed the 2013 Framework and integrated the changes into the Company’s internal controls over financial reporting. We expect that management’s assessment of the overall effectiveness of our internal controls over financial reporting for the year ending December 31,2014 will be based on the 2013 Framework and that the change will not be significant to our overall control structure over financial reporting.
As of September 30 2014, there were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II: OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of JuneSeptember 30, 2014.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.511.53 billion ($685629 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings.proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. The expert has been nominated by the FDC. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn, the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1.51.6 million ($680656 thousand) as of JuneSeptember 30, 2014, or pay an indemnification amount of approximately R$15 million ($76 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.51.6 million ($680656 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo.
In December 2001, Gridco Ltd. ("Gridco") served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal's awards with the local Indian court. Gridco's challenge of the costs award has been dismissed by the court, but its challenge of the liability award

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remains pending. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. The lawsuit remains before the FCSP, but the FCSP has suspended the lawsuit pending a decision on MPF's interlocutory appeal. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($32 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to remediatecontain and remove the contaminated areacontamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the remediationremoval work. In May 2012, CEEE began the remediationremoval work in compliance with the injunction. The remediationremoval costs are estimated to be approximately R$60 million ($2725 million) and the work is ongoing.was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The parties have until November 2014 to present their response to the report of the court-appointed expert. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal remains pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous

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obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the

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award in Argentine court. In June 2014, at AESU's request, a Uruguayan court temporarily enjoined YPF from pursuing its action in the Argentine court, pending a final determination by the Uruguayan court on whether YPF is entitled to challenge the liability award in the Argentine court. It is unclear whether YPF will complyhas not complied with the temporary injunction.injunction to date. In August 2014, a Uruguayan appellate court issued a decision declaring that only the Uruguayan courts have jurisdiction to review awards in the arbitration and that the Tribunal must disregard litigation outside of Uruguay when deciding issues in the arbitration. In October 2014, an Argentine appellate court issued a decision purporting to suspend the arbitration, and later issued an order threatening sanctions against violations of its decision. Given the competing decisions of the Uruguayan and Argentine courts, the Tribunal has suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal will consider whether to lift the suspension. In the arbitration,meantime, the Tribunal has asked the parties are submitting their respective evidence on damages. The final evidentiary hearing on damages will take place on November 6-7, 2014.to remove any alleged obstacles to the progress of the arbitration. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million)648 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($2 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($76 million) from UK HPP and KZT 1.3 billion ($7 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful.
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 4950 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproductsby-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April

62



2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits as well as any subsequently filed similar lawsuits. The Superior Court hasbetween April 2010 and November 2011, and may also ordered that, forstay the present,October 2014 lawsuit. Presently, discovery will proceedis proceeding only in the November 2009 lawsuit and will be limited toon causation

59



and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($327304 million) in the arbitration, plus interest and costs. The evidentiary hearing took place on November 27-December 6, 2013, and January 6-17, 2014. Closing arguments were heard on May 21-22, 2014. The parties are awaiting the Tribunal's award. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($454410 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction inof the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. The Park Administrator subsequently approved a new area for the recovery project. Eletropaulo is currently awaiting the draft of the agreement by the environmental agency, and expects to proceed with the recovery project after reaching agreement with the environmental agency.
In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of São Paulo Federal Court against the Brazilian Regulatory Agency (“ANEEL”), Eletropaulo and all other distribution companies in the State of São Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserted that the distribution companies’ tariffs had been incorrectly calculated by ANEEL, and that the tariffs were required to be corrected from the effective dates of the relevant concession contracts. SOSC asserted that ANEEL erred in May 2010, when the agency corrected the alleged error going forward but declared that the tariff calculations made in the past were correct. Eletropaulo opposed the lawsuit on the ground that it had not wrongfully collected amounts from its customers, as its tariffs had been calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. Subsequently, the lawsuit was transferred to the Federal Court of Belo Horizonte ("FCBH"), which was presiding over similar lawsuits against other distribution companies and ANEEL. In January 2014, the FCBH dismissed the lawsuit against Eletropaulo and the other distribution companies. Incompanies ("January 2014 Decision"). An appeal was filed in May 2014, SOSC appealedbut that decision.appeal was unsuccessful. The January 2014 Decision has become final and unappealable. SOSC's lawsuit will continue against ANEEL. If SOSC ultimately

63



prevails against the agency, it is possible that SOSC may file a new lawsuit against Eletropaulo seeking refunds. Eletropaulo estimates that its liability to customers could be approximately R$855 million ($388 million). Eletropaulo believes it has meritorious defenses and willwould vigorously defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.any such lawsuit.
In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$2.82.86 billion ($1.271.17 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. Eletropaulo believes it has

60



meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$844854 million ($383350 million) as estimated by AES Tietê. AES Tietê has filed an appeal to the Second Instance Administrative Court. No tax is due while the appeal is pending. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas ("Camara") perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its report to date. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has not yet established the procedural schedule for the arbitration.arbitration, but has not yet scheduled the final evidentiary hearing. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assuranceassurances that they will be successful in their efforts.
In April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately KZT 720 million ($4.03.9 million) in damages ("April 2013 Order”). The ED claimed that UK CHP was illegally operating without an emissions permit for 27 days in February-March 2013. In June 2013, the ED filed a lawsuit with the Specialized Interregional Economic Court (the “Economic Court”) seeking to require UK CHP to pay the assessed damages. UK CHP thereafter filed a separate lawsuit with the Economic Court challenging the April 2013 Order and the ED's allegations. In that lawsuit, in August 2013, the Economic Court ruled in UK CHP's favor and required the ED to vacate the April 2013 Order. That ruling was upheld on two intermediate appeals; however,appeals and thereafter the ED maydid not further appeal to the Kazakhstan Supreme Court. The Economic Court also dismissed the lawsuit filed by the ED. UK CHP believes it has meritorious claims and defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurance that it will be successful in its efforts.
In December 2013, AES Changuinola’s EPC Contractor initiated arbitration pursuant to the parties’ EPC Contract and related settlement agreements. The Contractor alleged, among other things, that AES Changuinola failed to make a settlement payment, release retainage, and acknowledge completion of AES Changuinola hydropower facility. In total, the Contractor sought approximately $41 million in damages, plus interest and costs. AES Changuinola denied the claims and asserted counterclaims against the Contractor. In July 2014, the parties settled the dispute.
ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors as previously disclosed in our 2013 Form 10-K under Part 1 — Item 1A. — Risk Factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information regarding purchases made by The AES Corporation of its common stock:
Repurchase Period Total Number of Shares Purchased Average Price Paid Per Share 
Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1)
 Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan
4/1/2014 - 4/30/14 —
 $—
 —
 $191,479,504
5/1/2014 - 5/31/14 1,165,334
 13.73
 1,165,334
 175,481,733
6/1/2014 - 6/30/14 1,140,379
 13.89
 1,140,379
 159,636,730
Total 2,305,713
 $13.81
 2,305,713
  
Repurchase Period Total Number of Shares Purchased Average Price Paid Per Share 
Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1)
 
Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan (2)
7/1/2014 - 7/31/14 —
 $—
 —
 $299,636,730
8/1/2014 - 8/31/14 2,594,646
 14.67
 2,594,646
 261,596,648
9/1/2014 - 9/30/14 4,783,741
 14.57
 4,783,741
 191,963,430
Total 7,378,387
 $—
 7,378,387
  
_____________________________

6164



(1)
(1) See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
(2) The authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans) and/or privately negotiated transactions. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time.
See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
4.1Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014.
   
31.1 Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
  
31.2 Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O’Flynn (filed herewith).
  
32.1 Section 1350 Certification of Andrés Gluski (filed herewith).
  
32.2 Section 1350 Certification of Thomas M. O’Flynn (filed herewith).
  
101.INS XBRL Instance Document (filed herewith).
  
101.SCH XBRL Taxonomy Extension Schema Document (filed herewith).
  
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).
  
101.DEF XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).
  
101.LAB XBRL Taxonomy Extension Label Linkbase Document (filed herewith).
  
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).


6265



SIGNATURES
Pursuant to the 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.

   
THE AES CORPORATION
(Registrant)
        
Date:August 6,November 5, 2014By: 
/s/ THOMAS M. O’FLYNN
     Name: Thomas M. O’Flynn
     Title: Executive Vice President and Chief Financial Officer (Principal Financial Officer)
        
   By: 
 /s/ SHARON A. VIRAG
     Name: Sharon A. Virag
     Title: Vice President and Controller (Principal Accounting Officer)


6366
s in millions)		 (
Adjusted Pretax Contribution: For a reconciliation of Adjusted PTC to net income from continuing operations, see Note 12 — Segments included in Item 1. — Financial Statements of this Form 10-Q.

35



Adjusted EPS
  Three Months Ended June 30, Six Months Ended June 30, 
Reconciliation of Adjusted Earnings Per Share 2014 2013 2014 2013 
Diluted earnings per share from continuing operations $0.20
 $0.22
 $0.13
 $0.37
 
Unrealized derivative (gains) losses (1)
 (0.02) (0.05) (0.03) (0.03) 
Unrealized foreign currency transaction (gains) losses (2)
 —
 0.04
 0.03
 0.05
 
Disposition/acquisition (gains) losses —
 (0.03)
(3) 
—
 (0.03)
(4) 
Impairment losses 0.09
(5) 
—
 0.26
(6) 
0.05
(7) 
Loss on extinguishment of debt 0.01
(8) 
0.17
(9) 
0.14
(10 
) 
0.21
(11) 
Adjusted earnings per share $0.28
 $0.35
 $0.53
 $0.62
 
  Three Months Ended September 30, Nine Months Ended September 30, 
Reconciliation of Adjusted Earnings Per Share 2014 2013 2014 2013 
Diluted earnings per share from continuing operations $0.67
 $0.23
 $0.81
 $0.61
 
Unrealized derivative (gains) losses (1)
 0.01
 —
 (0.02) (0.04) 
Unrealized foreign currency transaction (gains) losses (2)
 0.06
 (0.02) 0.07
 0.04
 
Disposition/acquisition (gains) losses (0.51)
(3) 
—
 (0.51)
(4) 
(0.03)
(5) 
Impairment losses 0.08
(6) 
0.18
(7) 
0.34
(8) 
0.23
(9) 
Loss on extinguishment of debt 0.06
(10) 
—
 0.20
(11 
) 
0.20
(12) 
Adjusted earnings per share $0.37
 $0.39
 $0.89
 $1.01
 
_____________________________
(1) 
Unrealized derivative (gains) losses were net of income tax per share of $(0.01)$0.00 and $(0.02)$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $(0.01) and $(0.02)$(0.03) in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
(2) 
Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00$0.03 and $0.00$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $0.01$0.04 and $0.01 in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
(3) 
Amount primarily relates to the gain from the sale of the remaining 20%a noncontrolling interest in Cartagena for $20Masinloc of $283 million ($15283 million, or $0.02$0.39 per share, net of income tax per share of $0.01).$0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per

38



share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction.
(4) 
Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction.
(5)
Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena forof $20 million ($1514 million, or $0.02 per share, net of income tax per share of $0.01), the gain from the sale of wind turbines for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00), the gain from the sale of Trinidad for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00) as well as the gain from the sale of Chengdu, an equity method investment in China forof $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00).
(5)(6) 
Amount primarily relates to the assetother-than-temporary impairment of our equity method investment at EbuteEntek of $52$18 million ($3412 million, or $0.05$0.02 per share, net of income tax per share of $0.02) and$0.01), the asset impairment at NewfieldEbute of $11$15 million ($6 million, or $0.00 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).
(6)
Amount primarily relates to the goodwill impairments at DPLER of $136 million ($92 million, or $0.13 per share, net of income tax per share of $0.06), at Buffalo Gap of $18 million ($1823 million, or $0.03 per share, net of income tax per sharenoncontrolling interest of $0.00)$1 million and asset impairments at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02)$(0.01)), at Newfieldand a tax benefit of $11$25 million ($6 million, or $0.000.03 per share, net of income tax per share of $0.00),share) associated with the previously recognized goodwill impairment at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).DPLER.
(7) 
Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also includes asset impairment at Beaver ValleyItabo (San Lorenzo) of $46$15 million ($346 million, or $0.05$0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).
(8) 
Amount primarily relates to the loss on early retirementgoodwill impairments at DPLER of debt$136 million ($117 million, or $0.16 per share, net of income tax per share of $0.03), and at CorporateBuffalo Gap of $13$18 million ($18 million, or $0.03 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($57 million, or $0.08 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01), at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.01), and at Newfield of $11 million ($6 million, or $0.00 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00) as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($28 million, or $0.04 per share, net of income tax per share of $0.02) and at Entek of $18 million ($12 million, or $0.02 per share, net of income tax per share of $0.01).
(9) 
Amount primarily relates to the loss on early retirementother-than-temporary impairment of debtour equity method investment at CorporateElsta in the Netherlands of $163$122 million ($12189 million, or $0.16$0.12 per share, net of income tax per share of $0.06)$0.04). Amount also includes the asset impairment at Beaver Valley of $46 million ($33 million, or $0.04 per share, net of income tax per share of $0.02), the asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as the goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).
(10) 
Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $145$43 million ($9925 million, or $0.14$0.03 per share, net of income tax per share of $0.06)$0.03), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $6 million ($3 million, or $0.00 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(11) 
Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $188 million ($123 million, or $0.17 per share, net of income tax per share of $0.09), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $8 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(12)
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $165 million ($123120 million, or $0.16 per share, net of income tax per share of $0.06) and at Masinloc of $43 million ($29 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01).

Operating Margin and Adjusted PTC Analysis
US SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $144
 $147
 $(3) -2 % $278
 $292
 $(14) -5 %
Noncontrolling Interests Adjustment —
 —
     —
 —
    
Derivatives Adjustment —
 (13)     9
 —
    
Adjusted Operating Margin $144
 $134
 $10
 7 % 287
 292
 $(5) -2 %
Adjusted PTC $80
 $63
 $17
 27 % $155
 $196
 $(41) 21 %
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $222
 $206
 $16
 8% $500
 $498
 $2
 —%
Noncontrolling Interests Adjustment —
 —
     —
 —
    
Derivatives Adjustment 5
 2
     14
 2
    
Adjusted Operating Margin $227
 $208
 $19
 9% 514
 500
 $14
 3%
Adjusted PTC $156
 $132
 $24
 18% $311
 $328
 $(17) 5%
Operating marginMargin for the three months ended JuneSeptember 30, 2014 decreased $3increased $16 million, or 2%8%. This performance was driven primarily by the following businessesbusiness and key operating drivers:
DPL decreased $19 million, primarily due to a $15 million impact from unrealized mark-to-market gains on derivatives in 2013 that did not recur, combined with a decrease in sales volumes, partially offset by an increase in retail rates.
This decrease was partially offset by:
US GenerationOhio increased by $14 million, primarily due to $8regulatory retail rate increases and reduced fuel and purchase power costs of $41 million, relating to the implementationpartially offset by decreased retail sales of the synchronous condensers to provide ancillary services in June 2013 at Southland, $3$25 million due to the completion of

36



the Tait energy storage project at DPL in September 2013,resulting from customer switching and an increase in market prices relating to production at Laurel Mountain of $2 million. mild weather.
Adjusted Operating Margin increased $1019 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin.
Adjusted PTC increased $1724 million driven by a $3$5 million gain recognized from proceeds relatingat Buffalo Gap, due to a bankruptcy settlement at Laurel Mountain,an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest (See Note 1 — General and Summary of Significant Accounting Policies — Noncontrolling Interests included in Item 8. — Financial Statements and Supplementary Data in the Company's 2013 Form 10-K) as well as the increase of $1019 million in Adjusted Operating Margin described above.

39



Operating marginMargin for the sixnine months ended JuneSeptember 30, 2014 decreased $14increased $2 million, or 5%0.4%. This performance was driven primarily by the following businesses and key operating drivers:
DPL decreased $48US Generation increased by $32 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $7 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 and lower fixed costs at Southland, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and
IPL in Indiana increased $4 million driven by higher wholesale and retail margin of $13 million, partially offset by higher fixed costs and depreciation of $9 million.
These increases were partially offset by:
DPL decreased $34 million, primarily due to decreases of $31 million attributable to outages and lower gas availability, which resulted in higher purchased power and related costs to supply higher demand from cold weather during the first quarter as well as outages and lower gains on unrealized derivativederivatives of $13 million in the second quarter.
This decrease was The results above were partially offset by:
US Generation increased by $33 million, primarily due to $11 millionimprovements in Q3 resulting from increased availability as a resultretail rates and lower fuel costs of fewer outages at Hawaii, $11 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 at Southland, $8 million at Laurel Mountain due to increased market prices relating to production, and $6 million due to the completion 2013 of the Tait energy storage project in September 2013.$16 million.
Adjusted Operating Margin decreased $5increased $14 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin.
Adjusted PTC decreased $41$17 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, partially offset by an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $10 million, settlements at Laurel Mountain of $6 million, as well as the decreaseincrease of $5$14 million in Adjusted Operating Margin described above.
Andes SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $148
 $148
 $—
 —% $239
 $282
 $(43) -15 %
Noncontrolling Interests Adjustment 32
 34
     56
 71
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $116
 $114
 $2
 —% $183
 $211
 $(28) -13 %
Adjusted PTC $104
 $88
 $16
 18% $157
 $169
 $(12) 7 %
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $212
 $134
 $78
 58% $451
 $416
 $35
 8%
Noncontrolling Interests Adjustment 53
 29
     109
 100
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $159
 $105
 $54
 51% $342
 $316
 $26
 8%
Adjusted PTC $120
 $109
 $11
 10% $277
 $278
 $(1) —%
Including the neutralunfavorable impact of foreign currency translation and remeasurement of $3 million, operating margin for the three months ended JuneSeptember 30, 2014 remained flat.increased $78 million, or 58%. This performance was driven primarily by the following businesses and key operating drivers:
Chivor in Colombia increased $55 million as higher inflows resulted in higher generation and spot sales of $44 million as well as higher rates of $6 million.
Gener in Chile increased $30 million due to higher coal and diesel availability of $19 million, and favorable contract and spot prices of $10 million in the SIC market.
This increase was offset by:
Argentina increaseddecreased $6 million driven by higher rates of $17 million related to the Resolution 529 adjustment (retroactive from February 2014), offset by higher fixed costs of $9 million mainly caused by inflation, adjustments.
This increase was offset by:
Gener in Chile decreased $4 million due to lower spot prices and lower margins on Energy Plus contracts at Termoandesgeneration of $8$7 million, and lower contract prices at Norgenerunfavorable foreign exchange rate impact of $5$4 million, partially offset by lower fixed costs from lower maintenancehigher rates of $8 million; and
Chivor in Colombia decreased $2$16 million from higher fixed costs related to the tunnel maintenance, partially offset by higher ancillary services and spot prices.Resolution 529 adjustment.
Adjusted Operating Margin increased $254 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.

37



Adjusted PTC increased $1611 million, driven by the increase of $254 million in Adjusted Operating Margin described above, partially offset by a non-recurring benefit of $20 million from FONINVEMEM III interest income on receivables in 2013 in Argentina and lower realized foreign currency lossesequity in earnings at Guacolda in Chile of $15 million in Chile.$12 million.
Including the unfavorable impact of foreign currency translation and remeasurement of $3$7 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $43increased $35 million, or 15%8%. This performance was driven primarily by the following businesses and key operating drivers:

40



Chivor in Colombia increased $52 million largely driven by significantly higher generation of $51 million resulting in higher spot and contract sales and ancillary services.
This increase was offset by:
Gener in Chile decreased $44$14 million, largely driven by lower availability in the first quarter due primarily to planned outages of $22 million, a reduction of $39$29 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $6 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $9 million;$10 million.
Chivor in ColombiaArgentina decreased $3$4 million driven by higher fixed costs as described above and lower foreign currency exchange rates,of $25 million driven by higher inflation; partially offset by higher prices and AGC sales; and
Argentina increased $3 million driven by higher rates of $17$21 million as a result of the impact of Resolution 529, partially offset by higher fixed costs of $16 million driven by higher inflation adjustment.529.
Adjusted Operating Margin decreased $28increased $26 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC decreased $12$1 million, driven by the decreaseincrease of $28$26 million in Adjusted Operating Margin described above, partiallyprimarily offset by higher equity earningsa non-recurring benefit in 2013 from the sale of a transmission line of Guacolda and lower realized foreign currency losses in Chile.FONINVEMEM III interest income on receivables as discussed above.
Brazil SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $270
 $313
 $(43) -14 % $591
 $516
 $75
 15%
Noncontrolling Interests Adjustment 188
 223
     423
 372
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $82
 $90
 $(8) -9 % $168
 $144
 $24
 17%
Adjusted PTC $115
 $78
 $37
 47 % $184
 $120
 $64
 53%
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $44
 $306
 $(262) -86 % $635
 $822
 $(187) -23 %
Noncontrolling Interests Adjustment 29
 208
     453
 580
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $15
 $98
 $(83) -85 % $182
 $242
 $(60) -25 %
Adjusted PTC $—
 $84
 $(84) -100 % $184
 $204
 $(20) 10 %
Including the unfavorable impact of foreign currency translation of $23 million, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreased $43$262 million, or 14%86%. This performance was driven primarily by the following businesses and key operating drivers:
Uruguaiana decreased $39 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation volumes from a temporary restart of operations;
Tietê decreased $12$202 million, driven by unfavorable foreign exchange rates of $16 million anddue to lower hydrology which led to lower generation volumes of $40 million as a result of low water inflows, partially offset byand an increase in energy purchases at higher spot prices of $45 million; andprices;
Eletropaulo decreased $5$29 million due to higher fixed costs of $53$39 million, including higher payroll and pension expense, as well as higher depreciation and unfavorable impact of foreign exchange, partially offset by $59$15 million of higher rates as a result of the July 20132014 tariff adjustmentadjustment; and volume.
These decreases were partially offset by:
Sul increaseddecreased by $13$26 million driven by lower volume and higher volumes from warmer weather of $10 million.fixed costs.
Adjusted Operating Margin decreased $883 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increasedecreased $3784 million, asdue to the decrease of $883 million in Adjusted Operating Margin as described above was offset by the reversal of a loss contingency related to interest expense of $47 million at Sul that is no longer considered probable.above.

38



Including the unfavorable impact of foreign currency translation of $83 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 increased $75decreased $187 million, or 15%23%. This performance was driven primarily by the following businesses and key operating drivers:
Tietê increased $74decreased $129 million, driven by a net impact of $142 million related to higher sales in the spot market, partially offset by lower contracted volumes of energy sold to Eletropaulo, and unfavorable foreign exchange rates of $61 million;
Eletropaulo increased $24 million, driven by higher tariffs and volume of $99 million, partially offset by unfavorable foreign exchange rates of $17 million and the net impact of $61 million of lower hydrology which led to lower generation and an increase in energy purchases at higher fixed costs of $56 million; and
Sul increased $23 million, due to higher volume of $35 million,prices, partially offset by higher fixed cost expensespot sales in first half of $3 million mainly related to services,2014 due to the stormy weather, and unfavorable foreign exchange rateslower contracted volumes of $5 million.
These increases were partially offset by:energy sold;
Uruguaiana decreased $46$48 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.operations;
Eletropaulo decreased $5 million, driven by higher fixed costs and depreciation of $103 million and unfavorable foreign exchange rates of $16 million, partially offset by higher tariffs and volume of $114 million; and
Sul decreased $3 million, due to higher fixed cost and depreciation expense of $14 million mainly driven by storm related maintenance costs, lower rates of $10 million due to the April 2013 tariff reset, and unfavorable foreign exchange rates of $4 million, partially offset by higher volume of $26 million.
Adjusted Operating Margin increased $24decreased $60 million primarily due to the drivers discussed above, adjusted for the impact of noncontrollingnon-controlling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.

41



Adjusted PTC increased $64decreased $20 million, driven by the increasedecrease of the $24$60 million in Adjusted Operating Margin described above and higher interest rates and debt, partially offset by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million at Sul that is no longer considered probable, partially offset by higher interest expense, as a result of an increase in interest rates.probable.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $146
 $149
 $(3) -2 % $235
 $254
 $(19) -7 %
Noncontrolling Interests Adjustment 17
 12
     10
 31
    
Derivatives Adjustment (3) (1)     (2) (1)    
Adjusted Operating Margin $126
 $136
 $(10) -7 % $223
 $222
 $1
 — %
Adjusted PTC $95
 $104
 $(9) -9 % $160
 $160
 $—
 0%
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $176
 $143
 $33
 23% $411
 $397
 $14
 4%
Noncontrolling Interests Adjustment 20
 14
     30
 45
    
Derivatives Adjustment —
 —
     (2) (1)    
Adjusted Operating Margin $156
 $129
 $27
 21% $379
 $351
 $28
 8%
Adjusted PTC $124
 $96
 $28
 29% $284
 $256
 $28
 11%
Including the unfavorable impact of currency translation of $1 million, operating margin for the three months ended JuneSeptember 30, 2014 decreased $3increased $33 million, or 2%23%. This performance was driven primarily by the following businesses and key operating drivers:
Dominican Republic increased $23 million, mainly related to the favorable impact of rates of $29 million due to lower fuel prices, higher PPA prices, and higher prices of gas sales to third parties; and
Panama decreased $8increased $12 million, driven by the Esti tunnel settlement agreement received during the second quarter of 2013 of $31 million, partially offset by a compensation from the government of Panama of $16$13 million related to spot purchases driven by dry hydrological conditions, as well as lower fixed costs of $7 million; and
El Salvador decreased $4 million, due primarily to higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $11 million, mainly related to higher sales due to higher generation of $15 million, as well as higher availability during Q2 2014 of $9 million, partially offset by lower volume of gas sales to third parties of $8 million and higher fuel prices of $5 million.conditions.
Adjusted Operating Margin decreaseincreased $10$27 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC decreaseincreased $928 million, driven by the decreaseincrease of $1027 million in Adjusted Operating Margin as described above.

39



Including the unfavorable impact of currency translation of $2$4 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $19increased $14 million, or 7%4%. This performance was driven primarily by the following businesses and key operating drivers:
Dominican Republic increased $59 million, mainly related to lower fuel costs of $31 million and higher PPA prices of $12 million, higher availability of $20 million and related lower maintenance expenses of $8 million, partially offset by lower gas sales to third parties of $11 million.
This increase was partially offset by:
Panama decreased $39$27 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $45$51 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of $23$36 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs during 2014 of $14$17 million; and
El Salvador decreased $18$15 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $36 million, mainly related to higher availability of $17 million, lower maintenance and other costs of $7 million and higher PPA prices of $12 million.
Mexico increased $5 million, mainly driven by higher availability.
Adjusted Operating Margin increased $1$28 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC remained flat,increased $28 million, driven by the increase of $1$28 million in Adjusted Operating Margin described above, partially offset by lower equity in earnings from the Trinidad business, which was sold in 2013.above.

42



EMEA SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our EMEA SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $77
 $86
 $(9) -10 % $210
 $200
 $10
 5%
Noncontrolling Interests Adjustment 5
 5
     11
 11
    
Derivatives Adjustment (4) —
     (4) —
    
Adjusted Operating Margin $68
 $81
 $(13) -16 % $195
 $189
 $6
 3%
Adjusted PTC $73
 $72
 $1
 1 % $188
 $168
 $20
 12%
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $94
 $85
 $9
 11% $304
 $285
 $19
 7%
Noncontrolling Interests Adjustment 7
 6
     18
 17
    
Derivatives Adjustment 4
 —
     —
 —
    
Adjusted Operating Margin $91
 $79
 $12
 15% $286
 $268
 $18
 7%
Adjusted PTC $79
 $66
 $13
 20% $267
 $234
 $33
 14%
Including the neutral impact of foreign currency translation, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreasedincreased $9 million, or 10%11%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014;
Maritza (Bulgaria)in Bulgaria increased $8 million, driven by better availability of $5 million related to timing of scheduled outages and lower depreciation of $3 million; and
Ebute in Nigeria increased $6 million primarily due to fewer outages of $2 million and lower depreciation of $2 million.
These increases were partially offset by:
Kilroot in the United Kingdom (U.K.) decreased $12$17 million driven by lower availability related to higher scheduled outages.
This decrease was partially offset by:
Kilroot (United Kingdom "U.K.") increased $5 million driven by higherdispatch and rates of $6 million, including income from energy price hedges, and strengthening of the British Pound, partially offset by higher outages of $2$14 million.
Adjusted Operating Margin decreaseincreased $1312 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $113 million, as a result of the decreaseincrease of $1312 million in Adjusted Operating Margin described aboveabove.
Including the unfavorable impact of foreign currency translation of $1 million, operating margin for the nine months ended September 30, 2014 increased $19 million, or 7%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014;
Ebute increased $7 million due to fewer outages of $6 million and lower depreciation;
Kazakhstan increased $6 million driven by higher generation volumes and rates of $19 million, partially offset by unfavorable foreign exchange impact of $8 million; and
Wind businesses in the U.K. increased $4 million, driven by higher contributions from Sixpenny Wood, Yelvertoft and Drone Hill, which were sold in August 2014.
These results were partially offset by:
Kilroot decreased $10 million, driven by lower dispatch and higher outages of $19 million, partially offset by higher rates of $11 million, including income from energy price hedges, and favorable foreign exchange impact.
Adjusted Operating Margin increased $18 million due to the drivers above adjusted for non-controlling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $33 million, driven primarily by the increase of $18 million in Adjusted Operating Margin, as well as a reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Including the favorable impact of foreign currency translation of $1 million, operating margin for the six months ended June 30, 2014 increased $10 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:
Kilroot (U.K.) increased $6 million, driven by higher rates, including income from energy price hedges, favorable FX,AES, partially offset by lower dispatch and higher outages;
Wind businesses (U.K.) increased $4 million, driven primarily by new business generation from Sixpenny Wood and Yelvertoft which commenced commercial operation in July 2013 and higher generation from Drone Hill;

40



Kazakhstan increased $3 million driven by higher generation volumes and rates, partially offset by unfavorable foreign currency; and
Ballylumford (U.K.) increased $2 million, due to higher volumes, partially offset by higher fixed costs.
These results were partially offset by:
Maritza (Bulgaria) decreased $6 million, driven primarily by higher scheduled outages, partially offset by higher rates.
Adjusted Operating Margin increased $6 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $20 million, driven primarily by the increase of $6 million in Adjusted Operating Margin, as well as a reversal of a liability in Kazakhstan as described above, partially offset by lower equity in earnings from Turkey.
Asia SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Asia SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $27
 $45
 $(18) -40 % $37
 $83
 $(46) -55 %
Noncontrolling Interests Adjustment 1
 3
     1
 5
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $26
 $42
 $(16) -38 % $36
 $78
 $(42) -54 %
Adjusted PTC $23
 $40
 $(17) -43 % $31
 $71
 $(40) 56 %
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $12
 $38
 $(26) -68 % $49
 $121
 $(72) -60 %
Noncontrolling Interests Adjustment 9
 2
     10
 7
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $3
 $36
 $(33) -92 % $39
 $114
 $(75) -66 %
Adjusted PTC $2
 $30
 $(28) -93 % $33
 $101
 $(68) 67 %

43



Operating margin for the three months ended JuneSeptember 30, 2014 decreased by $1826 million, or 40%68%. This performance was driven primarily by the following businesses and key operating drivers:
Masinloc (Philippines)in the Philippines decreased by $17$23 million driven by lower plant availability and related maintenance of $14 million and the net impact of lower spot sales and lower price of spot purchases of $2$18 million; and
Kelanitissa (Sri Lanka)in Sri Lanka decreased by $5$6 million driven by the step down in the contracted PPA price.price and higher outages and maintenance costs.
Adjusted Operating Margin decreased by $16$33 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc.
Adjusted PTC decreased by $17$28 million, driven by the decrease of $16$33 million in Adjusted Operating Margin described above.above, partially offset by the impact of lower proportional interest expense at Masinloc, and OPGC higher equity earnings.
Operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased by $46$72 million, or 55%60%. This performance was driven primarily by the following businesses and key operating drivers:
Masinloc (Philippines)in the Philippines decreased by $41$64 million, driven by $20$33 million due to lower plant availability, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher fixed costs of $5 million primarily due to maintenance, and net impact of higher contract demand at lower prices and lower spot sales and lower price of spot purchases of $5$4 million; and
Kelanitissa (Sri Lanka)in Sri Lanka decreased by $10$16 million driven by the step down in the contracted PPA price.
Adjusted Operating Margin decreased by $42$75 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc.
Adjusted PTC decreased by $40$68 million, driven by the decrease of $42$75 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc due to a 2013 debt refinancing.and gains on foreign currency.
Key Trends and Uncertainties
During the remainder of 2014 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors, a combination of factors, (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2013 Form 10-K.
Regulatory
Ohio—As noted in Item 1. — Business - United States— US SBU — Dayton Power & Light Company of the 2013 Form 10-K, an order was issued by the Public Utilities Commission of Ohio ("PUCO") in September 2013 (the “ESP Order”), which states that DP&L’s next ESP begins January 1, 2014 and extends through May 31, 2017.
On March 19, 2014, the PUCO issued a second entry on rehearing ("Entry on Rehearing") which changes some terms of
the ESP order. The Entry on Rehearing shortens the time by which DP&L must divest its generation assets to no later than
January 1, 2016 from May 31, 2017 in the ESP Order. The Entry on Rehearing also terminates the potential extension of the
Service Stability Rider on April 30, 2017 instead of May 31, 2017. In addition, the Entry on Rehearing accelerates DP&L’s
phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016, compared to 10% in 2014, 40%
in 2015, 70% in 2016 and 100% in June 2017 in the ESP Order. Parties, including DP&L, have filed applications for rehearing
on this Commission Order, which were granted in the PUCO’s third entry on rehearing on May 7, 2014.
On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the deadline by which DP&L must divest
its generation assets to January 1, 2017. The Ohio Consumer's Counsel has filed an application for rehearing on this Order,
which was denied by the PUCO. On June 30, 2014, several intervening parties filed a joint motion to stay collection of the Service Stability Rider while appeals are pending. This motion to stay was denied by the PUCO. The Industrial Energy Users of Ohio and the Ohio Consumer's Counsel filed Notices of Appeal of various aspects of the ESP Order and Entries on Rehearing to the Ohio Supreme Court on August 29, 2014 and September 22, 2014, respectively. On September 19, 2014, DP&L filed a Notice of Cross-appeal of the accelerated phase-in of the competitive bidding structure.

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In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets on or before May 31, 2017. DP&L amended its application on February 25, 2014 and again on May 23, 2014. On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications. Specifically, DP&L’s request to defer costs associated with the Ohio Valley Electric Corporation (OVEC) which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets. See Item 1. - — Business -— United States SBU -— Dayton Power & Light Company of the 2013 Form 10-K for further details of the ESP order and the filing to separate generation.
Philippines—In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, Energy Regulatory Commission ("ERC") declared the market prices from this period void and ordered the market operator to recalculate the prices for all market participants for November and December 2013 billing months. The recalculation of prices based on the load weighted average prices for the first nine months of 2013 resulted in an unfavorable adjustment of approximately $15 million to Masinloc spot sales. The ERC’s review of the motions for reconsideration filed by market participants including Masinloc is on-going. A secondary price cap was established for May and June 2014 and has been extended to mid-August,December, as a temporary measure to mitigate spot price impacts in the market. AtAs of this time the measure is expected to apply temporarilyhas not had a material impact on our business in 2014, in which case the impact may not be material.Philippines. However, if similar measures are implemented on a permanent basis, the impact could be material.
Dominican Republic— In August 2014, the Superintendence of Electricity (Sectoral Regulatory Body of the Electricity Sector), modified the rules for offering primary frequency regulation service, an ancillary service item. The former rules allocated the service to generators based on merit order and those which were the most flexible and could enter the system quickly generally satisfied the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by own source or through bilateral contracts with other generators who can offer the service, and any additional supply requirement must be allocated using the merit order process. As the AES businesses, Andres and Los Mina, were lower in the merit order they received a majority of the allocation under the former rules. The lower allocation of this service to these units under the new rules will have an impact of lowering the margin from frequency regulation which will be partially offset by higher energy dispatch.
Operational
Sensitivity to Dry Hydrological Conditions

Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Throughout 2013 and 2014, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in these markets. Low rainfall and water inflows caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. Some local forecasts suggest continued dry conditions for the remainder of 2014. Once rainfall and water inflows return to normal levels, high market prices and low generation could persist until reservoir levels are fully recovered.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and manages an Energythere is a mechanism called MRE (Energy Reallocation MechanismMechanism) created to share hydrological risk across all generators. If the system of hydroelectric generation facilities generates less than the assured energy of the system, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. We expect the system operator in Brazil to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 16 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices higher than historicalat high levels. During the first and second quarters of 2014, AES Tietê benefited from lower contract levels and captured spot sales at favorable prices. However, AES Tietê has higher contract obligations in the second half of 2014 and may needhas needed to fulfill some of these obligations with spot purchases, so itthey will be sensitive to generation output and spot prices for electricity during this period. Finally, if dry conditions persist in Brazil throughout 2014 and into the next rainy season, from NovemberDecember 2014 to April 2015, there is a risk that the

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government of Brazil could implement a rationing program in 2015, which could have a material adverse impact on our results of operations and cash flows.
In Panama, dry hydrological conditions continue to reduce generation output from hydroelectric facilities and have increased spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during the peak hours by approximately 300 MW, which contributed to water savings in the key hydroelectric dams and lower spot prices. AES Panama has had to purchase energy on the spot market to fulfill its contract obligations when its generation output is below its contract levels, and we expect this trend to continue for the remainder of the year. As authorized on March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70MW reduction in contracted capacity for the period

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2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016. Compensation payments recognized through September 30, 2014 were $36 million, of which $12 million are pending to be collected. AES owns 49% of AES Panama. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $26 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015.
Taxes
Chilean Tax Reform
On April 1,September 29, 2014, the Chilean government sent to Congress a bill proposingenacted comprehensive tax reforms. The proposed reforms would introducewhich introduced significant changes which, among others, include an increase in theto corporate income tax rate from 20% to 25% over a periodrates, modification of 4 years, the introduction of “Greenshareholder level income tax beginning in 2017, and new “green taxes” primarily over CO2 emissions and from 2017 a shareholder level tax on accrued profits rather than on actual dividends. The potential new legislation is being debatedalso beginning in Congress and could be subject to2017. See Note 17 — Income Taxes in Part I. Item 1. — Financial Statements of this Form 10-Q for further modification in the next several months. Should the bill be approved, the financial impact could be material.information.
Macroeconomic and Political
During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue.
Argentina — In Argentina, economic conditions are deteriorating, as measured by indicators such as non-receding inflation, diminishing foreign reserves, the potential for continued devaluation of the local currency, and a decline in economic growth. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At JuneSeptember 30, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 6 — Financing Receivables in Part I Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables. Although our businesses in Argentina have been able to access foreign currency for parts, equipment and equipmentfuel purchases and debt payments when needed, a further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets.
Argentina defaulted on its public debt in 2001, when it stopped making payments on about $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Argentina has expressed thatAlthough this situation remains unresolved, it will attempt to reach a satisfactory settlement agreement to unlock the current situation. This situation has not caused any significant changes that impact our current exposures other than those that are discussed above in regards to the macroeconomics within the country.
Bulgaria—Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned electricity public supplier and energy trading company. Maritza, a lignite-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by NEK. In November 2013, Maritza and NEK signed a rescheduling agreement for the overdue receivables as of November 12, 2013. Under the terms of the agreement, NEK paid $70 million of the overdue receivables and agreed to pay the remaining receivables in 13 equal monthly installments beginning December 2013. NEK has made payments according to the schedule through JulySeptember 2014. As of JuneSeptember 30, 2014, Maritza had outstanding receivables of $226 million, representing $43$50 million of current receivables, $30$14 million of the rescheduled receivables not yet due, $85$74 million of receivables overdue by less than 90 days and $69$88 million of receivables overdue by more than 90 days. On July 31, 2014 Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD

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(MMI), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17.3$17 million through an offset of payables due by Maritza to MMI. Additionally, NEK has agreed to four additional monthly installments totaling $27.6$28 million to be paid equally from August to November, 2014. Maritza has also received payments on outstanding receivables of $14.5 million subsequent to June 30, 2014 which were not under the tripartite agreement. Although Maritza continued to collect overdue receivables during the secondthird quarter of 2014 and thereafter, there continue to be risks associated with collections, which could result in a write-off of the remaining receivables and/or liquidity problems which could impact Maritza's ability to meet its obligations, if the situation around collections were to deteriorate significantly.
In May and June 2014, Bulgaria’s State Energy and Water Regulatory Commission (SEWRC) issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza,

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which could further impactimpacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. It is unclear whether NEK will abide by its obligations underHowever, SEWRC confirmed that until such negotiations conclude, the PPA or objectis in full force and effect and NEK has not objected to Maritza's invoices going forward.invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria.Bulgaria with the first hearing scheduled for the beginning of 2015. In addition, SEWRC announced that it has asked the Directorate-General for Competition of the European Commission (DG Comp) to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date.
On July 24, 2014, the Government of Bulgaria formally resigned.resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections are scheduled forwere held on October 5, 2014 to put2014. Eight political parties were elected and are currently discussing the formation of a new government in place. Installation of the new governmentwhich is expected to allow the negotiations to continue in a productive manner. Meanwhile the Caretaker Government requested and received the resignations of the former Chairman and two commissioners of the Regulator. The new leadership approved an end-consumer energy price increase of approximately 10% effective October 1, 2014, which is expected to slightly improve NEK's liquidity. The Caretaker Government also established an Energy Board, which is consultative body comprised of members who have an interest in the energy sector, with the objective to discuss and propose measures to be taken for stabilization of the energy sector. Maritza is a member of the Energy Board.
As a result of any of the foregoing events (including failure by NEK to honor its obligations under the PPA for any reason), we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value (including, without limitation, the value of receivables listed above) and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. For further information about the risks associated with the Company's investment in Maritza, see the following items in the Company's 2013 Form 10-K: Item 1— Business - EMEA; Item 1A. — Risk Factors of the 2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and Item 7: Management's Discussion & Analysis - Key Risks and Uncertainties.Uncertainties. See Note 8 — Debt included in Part I Item 1. — Financial Statements of this Form 10-Q for further information on current existing debt defaults. Further, Maritza is in litigation related to construction delays and related matters. For further information on the litigation see Part II Item 1. — Legal Proceedings.
Maritza will take all actions necessary to protect its interests, whether through negotiated agreement with NEK or through enforcement of its rights under the PPA. In addition, if necessary, Maritza will defend the PPA in any assessment or proceeding that may be initiated by DG Comp in response to SEWRC's request. As such, as of JuneSeptember 30, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.4$1.3 billion and total debt of $797$720 million, and Kavarna, which were $280$256 million and total debt of $190$176 million. Therefore, there is no reason to believemanagement believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014.
Puerto Rico— Our subsidiary in Puerto Rico has a long-term PPA with the Puerto Rico Electric Power Authority (“PREPA”), a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers. As a result of macroeconomic challenges in the country, including a seven-year recession, PREPA faces economic challenges including, but not limited to reliance on high cost fuel oil, decline in electricity sales, high customer power rates, high operating costs, past due accounts receivables from government institutions, and very low liquidity along with challenges obtaining financing due to the recent downgrades, and has struggled to honor its payment obligations to electricity generators on a timely basis. As a result, AES Puerto Rico's receivables balance has increased toas of September 30, 2014 is $95 million, outstanding as of June 30, 2014, of which $27$33 million is overdue and days sales outstanding from PREPA has deteriorated, which has caused our business to start to be delayed in our payments to suppliers. Subsequent to JuneSeptember 30, 2014, the overdue receivables of $27$30 million have been collected.
In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and it's public sector companies (PREPA included) to below investment grade. On June 28, 2014, the Governor of Puerto Rico signed into law the Recovery Act, which allows public corporations to adjust their debts in the interest of all creditors, and establishes procedures for the orderly enforcement. With the recent passing of the Recovery Act, the ratings were further reduced. S&PThe downgrade on PREPA has yet to lowerhad a direct impact on AES Puerto Rico's bonds, except for Moody's which rates the Commonwealth's rating butbonds above the state-owned corporation given AES Puerto Rico is expected to do so in the near term.lowest cost producer of electricity. We believe that AES Puerto Rico’s unique position as the lowest cost energy producer and cost-effective alternative for PREPA relative to fuel oil generated power, positions the business well and reduces the probability of negative impacts from a potential PREPA restructuring process. However there can be no assurance as to the final terms of any restructuring or potential impacts on AES Puerto Rico.
If AES Puerto Rico fails to receive payment in accordance with the terms of the PPA with PREPA, its liquidity issues could worsen, which could further impact AES Puerto Rico's ability to meet its obligations. See Item 1A. — Risk Factors of the

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2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and "We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations." As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
Our Puerto Rico business will take all actions necessary to protect its interests, whether through negotiated agreement with PREPA or through enforcement of its rights under the PPA. In October 2014, the Parent Company reached an agreement with an investor in AES Puerto Rico's preferred shares to retire the investment at a fixed redemption value of $52 million. The redemption is expected to be completed by the end of 2014. As the events pertaining to the Recovery Act continue to

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unfold, we concluded that there is no indicator of an impairment of the long-lived assets in Puerto Rico, which were $620$635 million and total debt of $584 million, and there is no reason to believe$594 million. Therefore, management believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014.
If global economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.
Impairments

Goodwill — Since its annual goodwill impairment test in the fourth quarter of 2013, the Company has been monitoring three reporting units, DP&L, DPLER and Buffalo Gap, as “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. In the first quarter of 2014, the Company recognized a full goodwill impairment of $136 million at DPLER and a goodwill impairment of $18 million at Buffalo Gap. The Company continues to monitor the remaining goodwill of $10 million at Buffalo Gap and the $316 million goodwill at DP&L. It is possible that the Company may incur goodwill impairment at DP&L, Buffalo Gap or any other reporting unit in future periods if certain events, such as, adverse changes in their business or operating environments occur.
Environmental
The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts) and certain air emissions, such as SOsulfur dioxide (SO2), NOnitrogen oxides (NOx), particulate matter (PM)and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. —- Risk Factors, “Our“Our businesses are subject to stringent environmental laws and regulations,,” “Our“Our businesses are subject to enforcement initiatives from environmental regulatory agencies,,” and “Regulators,“Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows”flows” set forth in the Company’s Form 10-K for the year ended December 31, 2013.2013. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. —- Business —- Regulatory Matters —- Environmental and Land Use Regulations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Item 2. —- Management's Discussion and Analysis of Financial Condition and Results of Operations —- Key Trends and Uncertainties —- Regulatory —- Environmental of the Company'sCompany’s Quarterly ReportReports on Form 10-Q for the fiscal quarterquarters ended March 31, 2014 and June 30, 2014.
UpdateTax on Greenhouse GasCarbon and Other Emissions Regulationsin Chile
In September 2014, the government of Chile enacted a carbon tax of $5.00 per ton of CO2, as well as taxes on emissions of PM, SO2 and NOx. The United States Environmental Protection Agency (“EPA”) issued proposed rules establishing greenhouse gas (“GHG”) performance standardsamount of the annual tax on PM, SO2 and NOx depends on volume and geographic location of the emissions, among other factors. This tax will be paid annually for existing power plants under Clean Air Act Section 111(d) on June 2, 2014. Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targetsin the previous year, beginning in 2020, with expected total U.S. power section2018 for emissions reductionin 2017. The financial impact to the Company of 30% from 2005 levels by 2030. The proposed rule requires states to submit

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implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances. The proposed rule will be subject to a public comment process during the course of this year, after which time EPA is expected to finalize it by President Obama’s June 1, 2015 deadline. Among other things, the Company's U.S.-based businessesthese taxes could be required to make efficiency improvements to existing facilities. However, it is too soon to determine what the rule, and the corresponding state implementation plans affecting the Company’s U.S.-based businesses, will require once they are finalized, whether they will survive judicial and other challenges, and if so, whether and when the rule and the corresponding state implementations plan would materially impact the Company’s business, operations or financial condition.
In addition,material in October 2013, the U.S. Supreme Court granted certiorari for several cases that address EPA’s authority to issue GHG Prevention of Significant Deterioration (“PSD”) permits under Section 165 of the CAA. In June 2014, the U.S. Supreme Court ruled that EPA had exceeded its statutory authority in issuing the so-called “Tailoring Rule” under Section 165 of the CAA by regulating all sources that emitted GHGs. However, the U.S. Supreme Court also held that EPA could impose GHG Best Achievable Control Technology (“BACT”) requirements for sources already required to implement under PSD for other pollutants. Therefore, if future modifications to the Company's U.S.-based businesses' sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the U.S. Supreme Court’s ruling and GHG BACT requirements applicable to the operation of the Company's U.S.-based businesses cannot be determined at this time as these businesses are not required to implement BACT until they construct a new major source or make a major modification of an existing major source. However, the cost of compliance could be material.
Update on MATS
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — MATS in the Company's Form 10-K for the year ended December 31, 2013, several lawsuits challenging the Mercury Air Toxics Standards (“MATS”) were filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). On April 15, 2014, a three-judge panel of the D.C. Circuit denied the challenges. Twenty-three states and certain industry groups have petitioned the United States Supreme Court to review the decision. We currently cannot predict whether the petition will be granted.
On June 20, 2014, IPL contemporaneously filed a waiver request/alternative complaint with the Federal Energy Regulatory Commission ("FERC") requesting a waiver that will allow IPL to keep 216 MW of reliable capacity available at its Eagle Valley generating station from June 1, 2015 through April 15, 2016. Both of these filings request that the FERC either waive or reform certain requirements of the Midcontinent Independent System Operator, Inc. market tariff for failing to address the specific circumstances resulting from compliance with MATS.
Update on Cooling Water Intake Structures Standards
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, the Company’s facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. On May 19, 2014, the EPA announced its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. These standards require subject facilities that utilize at least 25% of the withdrawn water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include public input as part of permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.periods.

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Update on Environmental Wastewater Requirements
As discussed in Item 1. Business - United States Environmental and Land Use Regulations - Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, certainDP&L is appealing various aspects of the Company’s U.S.-based businesses are subject toa National Pollutant Discharge Elimination System (“NPDES”) permit for J.M. Stuart Station issued by the Ohio EPA. NPDES permits that regulate specific industrial waste waterwastewater and storm water discharges to the watersinto a water of the United States under the FederalU.S. Clean Water Act (“CWA”). In June 2014, the EPA alongAct. It is believed that compliance with the U.S. Army Corpspermit as written will require capital expenses that will be material to DP&L. The cost of Engineers issuedcompliance and the timing of such costs is uncertain and may vary considerably depending on a proposed rule definingcompliance plan that would need to be developed, the waterstype of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the United States. This rulemakingfinal permit to the Environmental Review Appeals Commission and a hearing has been scheduled for March 2015. The compliance schedule in the potentialfinal permit has been modified to impact all programs underaccommodate the CWA. Expansion of regulated waterways is possible based on initial reviewtiming of the proposal, which may impact several permitting programs. Although we cannot at this time determine the timing or impacthearing. The outcome of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.such appeal is uncertain.
Update on the CSAPR
As furtherAlso as discussed in Item 1. 1. Business —- United States Environmental and Land Use Regulations — CAIR and CSAPR - Water Dischargesin the Company's Form 10-K for the year ended December 31, 2013, in responsethe Indiana Department of Environmental Management (“IDEM”) issued NPDES permits to the D.C. Circuit’s striking down muchIPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. These permits set new water quality-based levels of acceptable metal effluent water discharges for the EPA’s Clean Air Interstate Rule (“CAIR”)Petersburg and remanding itHarding Street facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance with the new metal effluent limitations required by October 2015. IPL received an extension to the EPA, the EPA issued a new rule in July 2011 titled “Federal Implementation Planscompliance deadline through September 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO2 and NOx emissions from covered sources, such as power plants, in certain states in which subsidiaries of the Company operate. Once fully implemented (originally planned for 2014), the rule would requiredetermine what operational changes and/or additional SO2 emission reductions of 73% and additional NOx reductions of 54% from 2005 levels. The CSAPR would be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPAequipment will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, the EPA would issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.
Upon petitions for review filed by many states, utilities and other affected parties, the D.C. Circuit vacated the CSAPR in August 2012 and required the EPA to continue administering CAIR pending the promulgation of a valid replacement to the CSAPR. Prior to this decision, the D.C. Circuit had granted a stay of the CSAPR. On April 29, 2014, the United States Supreme Court upheld the CSAPR, reversing the D.C. Circuit Court’s decision to vacate the CSAPR.
It is difficult to predict the steps that will follow this ruling. There remain numerous challenges to the CSAPR that must be addressed, some of which could again result in delay or invalidation of the CSAPR. On June 26, 2014, EPA filed a motion in the D.C. Circuit requesting that the court lift the stay of the CSAPR. EPA also requested that the court extend CSAPR’s compliance deadlines by three years, so that the Phase 1 emissions budgets that were to begin in 2012 would now apply starting in 2015, and the Phase 2 emissions that were to begin in 2014 would apply starting in 2017. The multiple parties to the litigation have filed oppositions to EPA’s motion to lift the stay and all parties have filed motions to govern further proceedings. If the D.C. Circuit grants EPA’s motion, the Company anticipates an increase in capital costs and other expenditures and operational restrictions that would be required to comply with the new limitations. On August 15, 2014, IPL announced its intent to file plans with the IURC to refuel Unit 7 at Harding Street from coal-fired to natural gas. This conversion is part of IPL's overall wastewater compliance plan for its power plants. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. IPL is seeking approval for a reinstated CSAPR. AtCertificate of Public Convenience and Necessity (CPCN) to install and operate wastewater treatment technologies at its Petersburg and Harding Street plants. If approved, IPL will invest $332 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. IPL expects to recover through its environmental rate adjustment mechanism, operating or capital expenditures related to compliance with these NPDES permit requirements. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact that such rules would haveof these permit requirements on the Company; they could have a material impact on the Company's business,our consolidated results of operations, cash flows, or financial condition, and results of operations.
IPL Unit Retirement and Replacement Generation
As discussed in Item 1. Business — United States Environmental and Land Use Regulations — Unit Retirement and Replacement Generation in the Company's Form 10-K for the year ended December 31, 2013, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to build a 550 MW to 725 MW combined cycle gas turbine (“CCGT”) at its Eagle Valley generating station and to refuel its Harding Street generating station Units 5 and 6 from coal to natural gas (about 100MW each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $626 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that we are allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGTbut it is expected to be placed into service in April 2017, and the refueling project is expected to be completed in early 2016. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service.material.


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Capital Resources and Liquidity
Overview
As of JuneSeptember 30, 2014, the Company had unrestricted cash and cash equivalents of $1.51.7 billion, of which approximately $15229 million was held at the Parent Company and qualified holding companies, and approximatelycompanies. The Company had $424686 million was held in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.0 billion967 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.915.7 billion and $5.85.3 billion, respectively. Of the approximately $2.12.3 billion of our current non-recourse debt, $1.1$1.4 billion was presented as such because it is due in the next twelve months and $1.00.9 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated

49



long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility and floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.915.7 billion of total non-recourse debt outstanding as of JuneSeptember 30, 2014, approximately $3.94.1 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At JuneSeptember 30, 2014, the Parent Company had provided outstanding financial and performance-related guarantees, indemnities or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $620 million$1.0 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At JuneSeptember 30, 2014, we had $1 million in letters of credit outstanding, provided under our senior secured credit facility, and $10297 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended JuneSeptember 30, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has

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near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.
As of JuneSeptember 30, 2014, the Company had approximately $258246 million and $3924 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond JuneSeptember 30, 2014, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6 — Financing Receivables included in Part I Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2013 Form 10-K for further information.
Consolidated Cash Flows
During the sixnine months ended JuneSeptember 30, 2014,, cash and cash equivalents decreaseincreased $127$28 million to $1.5$1.7 billion. The decreaseincrease in cash and cash equivalents was due to $453 million1.2 billion of cash provided by operating activities, $391364 million of cash used

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in investing activities, $250844 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $1455 million and a $75 million decrease in cash of discontinued and held-for-sale businesses.
Operating Activities — Net cash provided by operating activities decreased $732824 million to $453 million during the six months endedJune 30, 2014 compared to $1.2 billion during the sixnine months ended JuneSeptember 30, 2014 compared to $2 billion during the nine months endedSeptember 30, 2013. This performance was driven primarily by the following SBUs and key operating activities:
Brazil — a decrease of $505 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes;
MCAC — a decrease of $179 million at our generation businesses primarily due to higher working capital requirements; and
EMEA — a decrease of $94 million primarily due to higher working capital requirements.
OperatingNet cash flow forprovided by operating activities was $1.2 billion during the sixnine months ended JuneSeptember 30, 2014. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, impairment expenses and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $1 billion in operating assets and liabilities. This net use of cash forwithin operating activities of $1 billion was primarily due to the following:
an increase of $316494 million in accounts receivable primarily related to higher sales at Eletropaulo, Sul and Alicura and lower collections at Maritza;
an increase of $439 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs;
an increase of $312 million in accounts receivable primarily related to higher sales at Sul, Alicura and Gener, return of operations at Uruguaiana in March 2014 and lower collections at Maritza;
a decrease of $194 million in accounts payable and other current liabilities primarily at Eletropaulo relating to a decrease in regulatory liabilities;
a decrease of $176239 million in net income tax and other tax payables primarily related to payments of income taxes exceeding accruals for the 2014 tax liability.liability; partially offset by
an increase of $319 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by reduced pension contributions at IPL and payments for share-based compensation issuance tax and derivative termination at the Parent Company.
Net cash provided by operating activities was $1.22.0 billion during the sixnine months ended JuneSeptember 30, 2013. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $310255 million in operating assets and liabilities. This net use of cash forwithin operating activities of $310$255 million was primarily due to:
a decrease of $252$578 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and a decrease in value added taxes payables due to the lower tariff in 2013 andas well as at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision;
an increase of $147$149 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs;
partially offset by
a decrease of $134$403 million in net income taxprepaid expenses and other tax payablescurrent assets primarily from payment of income taxes exceeding accrualsdue to a decrease in current regulatory assets, for the tax liability on 2013 income, partially offset by an accrualrecovery of indirect taxes in Brazil; partially offset by
prior-period tariff cycle energy purchases and transportation costs at Eletropaulo and Sul; and
a decrease of $191$135 million in accounts receivable primarily duerelated to lower tariffs in 2013 at Eletropaulo and higher collections combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.

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The net decrease of cash flows from operating activities of $732 million for the six months endedJune 30, 2014 compared to the six months endedJune 30, 2013 was primarily the result of the following:
Brazil — a decrease of $442 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes and interest on debt.
US — a decrease of $160 million primarily due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating results and higher working capital requirements at DPL.
MCAC — a decrease of $154 million at our generation businesses primarily due to higher working capital requirements.
Investing Activities — Net cash used in investing activities was $391364 million during the sixnine months ended JuneSeptember 30, 2014 primarily attributable to the following:
Capital expenditures of $908 million1.4 billion consisting of $536$789 million of growth capital expenditures and $372$600 million of maintenance and environmental capital expenditures. Growth capital expenditures primarily included amounts at Gener of $250$303 million, Eletropaulo of $83$125 million,Vietnam Mong Duong of $45$72 million, Jordan of $71 million, IPL of $61 million and Jordan $38Sul of $35 million. Maintenance and environmental capital expenditures primarily included amounts at IPL of $105$178 million, Eletropaulo of $42$73 million, Tietê of $40$64 million, Gener of $50 million, DPL of $48 million and DPLSul of $32 million.$41 million;
Acquisitions, net of cash acquired of $728 million consisted of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 7 — Investment in and Advances to Affiliates in Item 1. — Financial Statements of this Form 10-Q for further information. These amounts wereinformation; partially offset by
Proceeds from the sale of businesses of $890 million with$1.7 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $443 million for the sale of 45% of our equity interest in Masinloc, $179 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and $160the United States and $156 million from the sale of our businessesbusiness in Cameroon,Cameroon; and

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Decreases in restricted cash, debt service reserves and other assets of $162 million including amounts at the USParent Company of $66 million, Maritza of $44 million and India; and
SalesAlto Maipo of short-term investments, net of purchases of $273 million primarily in Brazil.$37 million.
Net cash used in investing activities was $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:
Capital expenditures of $866 million$1.3 billion consisting of $454$690 million of growth capital expenditures and $412$640 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $138$188 million, Gener of $81$166 million, Jordan of $54$95 million, Sul of $44$57 million, Sixpenny WoodDPL of $22$28 million, Mong Duong of $19$27 million, Yelvertoft of $20 million, Kribi of $17 million and YelvertoftAltai of $19$16 million. Maintenance and environmental capital expenditures included amounts at IPALCOIPL of $87$164 million, Eletropaulo of $72$103 million, DPL of $63 million, Gener of $47$61 million, DPLTietê of $46$53 million, Sul of $39$50 million, Altai of $21 million and Itabo of $15 million;
Purchase of short-term investments, net of sales of $263 million including amounts at Eletropaulo of $212 million, Sul of $32 million and Tietê of $30$29 million; partially offset by
Proceeds from the sale of business, net of cash sold of $135$167 million including $113 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.

Net cash used in investing activities decreased $315903 million to $391364 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in investing activities of $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This net decrease was primarily due to an increase in proceeds from the sale of business, net of cash sold of $1.5 billion, a decrease in purchases of short-term investments, net of sales of $343212 million, partially offset by an increase in acquisitions of $725 million.
Financing Activities — Net cash used in financing activities was $250844 million during the sixnine months ended JuneSeptember 30, 2014. This was primarily attributable to the following:
Payments for financed capital expenditures of $312 million, primarily at Mong Duong with $272 million in payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to minority interests of $197 million primarily at Tietê with $109 million; and
Repayments of recourse and non-recourse debt of $3.03.7 billion including amounts at the Parent Company of $1.7$2 billion, Gener of $853$905 million, Tietê of $132 million, Maritza of $65 million, Shady Point of $52 million, Puerto Rico of $51 million and Puerto Rico$114 million related to the UK Wind sale;
Distributions to noncontrolling interests of $42$377 million including amounts at Tietê of $188 million, Brasiliana Energia of $65 million, Gener of $35 million and Buffalo Gap of $33 million;
Payments for financed capital expenditures of $360 million primarily at Mong Duong of $272 million; partially offset by
Issuances of recourse and non-recourse debt of $3.23.8 billion, including new issuances at the Parent Company of $1.5 billion, Gener of $700 million, Mong Duong of $298 million, Eletropaulo of $253 million, Cochrane of $173 million, IPL of $130 million and Tietê of $129 million; and a draw down under construction loan facility at Mong Duong of $272 million.
Net cash used in financing activities was $799635 million during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:

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Payments for financed capital expenditures of $257 million, primarily at Mong Duong for payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $211 million included amounts at Tietê of $98 million, Brasiliana of $34 million, Buffalo Gap of $25 million, and Gener of $18 million;
Payments for financing fees of $127 million included amounts at Cochrane of $41 million, Eletropaulo of $25 million, and Mong Duong of $13 million; and
Repayments of recourse and non-recourse debt of $3.4$3.5 billion primarilyincluded amounts at the Parent Company of $1.2 billion, Masinloc of $546 million, DPL of $425 million, Tietê of $396 million, El Salvador of $301 million, IPL of $110 million, Warrior Run of $87$93 million, Puerto Rico of $52$65 million, Maritza of $57 million, Sonel of $46 million and Sul of $37$40 million;
Payments for financed capital expenditures of $436 million, primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $385 million included amounts at Tietê of $154 million, Brasiliana Energia of $96 million, Gener of $39 million and MaritzaBuffalo Gap of $29$19 million;
Payments for financing fees of $148 million included amounts at Cochrane of $42 million, Eletropaulo of $25 million, Mong Duong of $20 million and the Parent Company of $17 million; partially offset by
Issuances of recourse and non-recourse debt of $3.1$3.8 billion,, including amounts at the Parent Company for $750 million, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $339 million, El Salvador of $310 million, Mong Duong of $210 million, DPL of $200 million, IPL of $170 million, Sul of $150 million, Jordan of $138 million, Cochrane of $82$120 million,Warrior Run of $74 million and Kribi of $63 million; and
Contributions from noncontrolling interests of $157 million including amounts at Mong Duong of $55 million, Alto Maipo of $50 million and JordanCochrane of $61$34 million.
Net cash used in financing activities decreasedincreased $549209 million to $250844 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in financing activities of $799635 million during the sixnine months ended JuneSeptember 30, 2013. This net decreaseincrease was primarily due to a decreasean increase in the repayments of recourse and non-recourse debt of $363 million and an increase in the issuance of recourse and non-recourse debt of $102162 million.

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Proportional Free Cash Flow (a non-GAAP measure)
We define Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below.
We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1. Business— US SBU — IPALCO — Environmental Matters in the 2013 Form 10-K for details of these investments.
The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the Company.
The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies

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  Three months ended June 30, Six months ended June 30,
  2014 2013 2014 2013
  (in millions)
Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below:        
Maintenance Capital Expenditures $152
 $174
 $289
 $360
Environmental Capital Expenditures 77
 42
 111
 73
Growth Capital Expenditures 414
 354
 820
 690
Total Capital Expenditures $643
 $570
 $1,220
 $1,123
Consolidated        
Net cash provided by operating activities $232
 $567
 $453
 $1,185
Less: Maintenance Capital Expenditures, net of reinsurance proceeds 152
 174
 289
 360
Less: Non-recoverable Environmental Capital Expenditures 25
 26
 36
 47
Free Cash Flow $55
 $367
 $128
 $778
Reconciliation of Proportional Operating Cash Flow        
Net cash provided by operating activities $232
 $567
 $453
 $1,185
Less: Proportional Adjustment Factor (1)
 64
 263
 44
 367
Proportional Operating Cash Flow $168
 $304
 $409
 $818
Proportional        
Proportional Operating Cash Flow $168
 $304
 $409
 $818
Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1)
 102
 121
 206
 258
Less: Proportional Non-recoverable Environmental Capital Expenditures (1)
 19
 18
 27
 34
Proportional Free Cash Flow $47
 $165
 $176
 $526
  Three months ended September 30, Nine months ended September 30,
  2014 2013 2014 2013
  (in millions)
Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below:        
Maintenance Capital Expenditures $169
 $166
 $458
 $526
Environmental Capital Expenditures 62
 72
 172
 145
Growth Capital Expenditures 298
 405
 1,119
 1,095
Total Capital Expenditures $529
 $643
 $1,749
 $1,766
Consolidated        
Net cash provided by operating activities $763
 $855
 $1,216
 $2,040
Less: Maintenance Capital Expenditures, net of reinsurance proceeds 169
 166
 458
 526
Less: Non-recoverable Environmental Capital Expenditures 16
 22
 52
 69
Free Cash Flow $578
 $667
 $706
 $1,445
Reconciliation of Proportional Operating Cash Flow        
Net cash provided by operating activities $763
 $855
 $1,216
 $2,040
Less: Proportional Adjustment Factor (1)
 208
 327
 251
 694
Proportional Operating Cash Flow $555
 $528
 $965
 $1,346
Proportional        
Proportional Operating Cash Flow $555
 $528
 $965
 $1,346
Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1)
 116
 114
 322
 372
Less: Proportional Non-recoverable Environmental Capital Expenditures (1)
 12
 17
 39
 51
Proportional Free Cash Flow $427
 $397
 $604
 $923
(1) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by non-controlling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 70% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $30 (or $100 x 30%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to non-controlling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur.
Proportional Free Cash Flow for the three months ended JuneSeptember 30, 2014 compared to the three months ended JuneSeptember 30, 2013 increased $30 million, driven by higher Proportional Operating Cash Flow and lower Proportional Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by increases from the following SBUs and key operating drivers:
US — driven by higher operating cash flow at the US Utilities driven by lower working capital requirements and higher earnings; and
Brazil — driven by Sul due to higher collections, partially offset by higher energy purchases and higher tax payments.
These increases were partially offset by decreases at:

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Asia — driven by Masinloc due to lower earnings and higher working capital requirements;
EMEA — driven by lower results for Wind entities driven by sale of UK Wind assets, sold in August 2014, and lower collections at Kavarna in Bulgaria as well as Kilroot in the U.K. driven by lower earnings;
MCAC — driven by higher working capital requirements as a result of lower collections and timing of inventory in the Dominican Republic.
Proportional Free Cash Flow for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 decreased $118$319 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance and Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by decreasesincreases from the following SBUs and key operating drivers:
MCAC — due todriven by higher working capital requirements in the Dominican Republic;Republic and Panama;
Brazil — driven by higher pricesprice of energy purchases as well asand higher taxes and interest on debt at Eletropaulo and Sul.Sul; and
These decreases were partially offset by an increase at:
CorpEMEA — driven by lower interest payments.
Proportional Free Cash Flow for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 decreased $350 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance Capital Expenditures. This performance was driven primarily by decreases from the following SBUs and key operating drivers:
Brazil — driven by higher prices of energy purchases as well as higher taxes and interest on debt at Eletropaulo and Sul;
MCAC — due to higher working capital requirements in the Dominican Republic; and
US — due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating resultsmargins and higher working capital requirementsin the U.K. and lower collections at DPL, partially offset by lower proportional maintenance capital expenditures.Maritza and Kavarna in Bulgaria.
Parent Company Liquidity
The following discussion of Parent Company Liquidity has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP as a measure of liquidity. Cash and cash equivalents are disclosed in the condensed consolidated statements of cash flows. Parent Company Liquidity may differ from similarly titled measures used by other companies.
The principal sources of liquidity at the Parent Company level are:

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dividends and other distributions from our subsidiaries, including refinancing proceeds;
proceeds from debt and equity financings at the Parent Company level, including availability under our credit facilities; and
proceeds from asset sales.
Cash requirements at the Parent Company level are primarily to fund:
interest;
principal repayments of debt;
acquisitions;
construction commitments;
other equity commitments;
common stock repurchases;
taxes;
Parent Company overhead and development costs; and
dividends on common stock.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at the periods indicated as follows:
Parent Company Liquidity June 30, 2014 December 31, 2013
  (in millions)
Consolidated cash and cash equivalents $1,515
 $1,642
Less: Cash and cash equivalents at subsidiaries 1,500
 1,510
Parent and qualified holding companies’ cash and cash equivalents 15
 132
Commitments under Parent credit facilities 800
 800
Less: Borrowings under the credit facilities (120) —
Less: Letters of credit under the credit facilities (1) (1)
Borrowings available under Parent credit facilities 679
 799
Total Parent Company Liquidity $694
 $931
Parent Company Liquidity September 30, 2014 December 31, 2013
  (in millions)
Consolidated cash and cash equivalents $1,670
 $1,642
Less: Cash and cash equivalents at subsidiaries 1,441
 1,510
Parent and qualified holding companies’ cash and cash equivalents 229
 132
Commitments under Parent credit facilities 800
 800
Less: Letters of credit under the credit facilities (1) (1)
Borrowings available under Parent credit facilities 799
 799
Total Parent Company Liquidity $1,028
 $931

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The Company paid a dividend of $0.05 per share to its common stockholders during the three months ended JuneSeptember 30, 2014. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends.
While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Considerations in this Item 2), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors “The, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.otherwise.” of the Company’s 2013 Form 10-K.
Various debt instruments at the Parent Company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:

limitations on other indebtedness, liens, investments and guarantees;
limitations on dividends, stock repurchases and other equity transactions;
restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;
maintenance of certain financial ratios; and

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financial and other reporting requirements.
As of JuneSeptember 30, 2014, the Parent Company was in compliance with these covenants.
Non-Recourse Debt
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;
causing us to record a loss in the event the lender forecloses on the assets; and
triggering defaults in our outstanding debt at the Parent Company.
For example, our senior secured credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.12.3 billion. The portion of current debt related to such defaults was $1.00.9 billion at JuneSeptember 30, 2014, all of which was non-recourse debt related to two subsidiaries — Maritza and Kavarna.
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of JuneSeptember 30, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of JuneSeptember 30, 2014, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.

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Critical Accounting Policies and Estimates
The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in our 2013 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2013 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policiesthese remain the Company’sas critical accounting policies as of and for the sixnine months ended JuneSeptember 30, 2014.
During the third quarter of 2014, the following additional critical accounting estimate was employed with respect to the Company's sales of noncontrolling interests:
Sales of Noncontrolling Interests
The accounting for a sale of noncontrolling interests under the accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders’ equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders’ equity. In-substance real estate is comprised of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates previously disclosed in our 2013 Form 10-K for impairments and fair value.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
Our generation and utility businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between

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our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
These disclosures set forth in this Item 3 are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2013 Form 10-K.
Commodity Price Risk
Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an

56



un-hedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.
When hedging the output of our generation assets, we utilize contract strategies that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk.
AES businesses will see changes in variable margin performance as global commodity prices shift. For the remainder of 2014, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $5 million for natural gas, $5 million for oil and less than $5 million for coal. Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. OffsetsExposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.
In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during some periods.
In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets.assets which can be an expensive cap depending on fuel pricing at the time required. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia, we

54



operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.
In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.
In the MCAC SBU, our businesses have commodity exposure on un-hedged volumes. Panama is largelyhighly contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.

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In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are un-hedged, the commodity risk at our Kilroot business is to the clean dark spread — the difference between electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, the regulator has the right to terminate the contract, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business.
In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume soldor shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.
Foreign Exchange Rate Risk
In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, KazakhstaniKazakhstan Tenge, Mexican Peso and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.
We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, British Pound, Brazilian Real, Colombian Peso, Euro and Kazakhstan Tenge. As of JuneSeptember 30, 2014, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro and Kazakhstan Tenge relative to the U.S. Dollar are projected to be reduced by approximately $5 million, $5 million, $5 million, $5 million, less than $5 million and $5 million respectively,for each currency for the remainder of 2014. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2014 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements.
Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-

55



recoursenon-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of JuneSeptember 30, 2014, the portfolio’s pretax earnings exposure for the remainder of 2014 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $10 million based on the impact of a one time, 100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”)CEO and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our

58



disclosure controls and procedures were effective as of JuneSeptember 30, 2014 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Controls over Financial Reporting
ThereOn May 14, 2013, The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We have reviewed the 2013 Framework and integrated the changes into the Company’s internal controls over financial reporting. We expect that management’s assessment of the overall effectiveness of our internal controls over financial reporting for the year ending December 31,2014 will be based on the 2013 Framework and that the change will not be significant to our overall control structure over financial reporting.
As of September 30 2014, there were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II: OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of JuneSeptember 30, 2014.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.511.53 billion ($685629 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings.proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. The expert has been nominated by the FDC. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn, the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1.51.6 million ($680656 thousand) as of JuneSeptember 30, 2014, or pay an indemnification amount of approximately R$15 million ($76 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.51.6 million ($680656 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo.
In December 2001, Gridco Ltd. ("Gridco") served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal's awards with the local Indian court. Gridco's challenge of the costs award has been dismissed by the court, but its challenge of the liability award

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remains pending. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. The lawsuit remains before the FCSP, but the FCSP has suspended the lawsuit pending a decision on MPF's interlocutory appeal. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($32 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to remediatecontain and remove the contaminated areacontamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the remediationremoval work. In May 2012, CEEE began the remediationremoval work in compliance with the injunction. The remediationremoval costs are estimated to be approximately R$60 million ($2725 million) and the work is ongoing.was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The parties have until November 2014 to present their response to the report of the court-appointed expert. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal remains pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous

61



obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the

58



award in Argentine court. In June 2014, at AESU's request, a Uruguayan court temporarily enjoined YPF from pursuing its action in the Argentine court, pending a final determination by the Uruguayan court on whether YPF is entitled to challenge the liability award in the Argentine court. It is unclear whether YPF will complyhas not complied with the temporary injunction.injunction to date. In August 2014, a Uruguayan appellate court issued a decision declaring that only the Uruguayan courts have jurisdiction to review awards in the arbitration and that the Tribunal must disregard litigation outside of Uruguay when deciding issues in the arbitration. In October 2014, an Argentine appellate court issued a decision purporting to suspend the arbitration, and later issued an order threatening sanctions against violations of its decision. Given the competing decisions of the Uruguayan and Argentine courts, the Tribunal has suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal will consider whether to lift the suspension. In the arbitration,meantime, the Tribunal has asked the parties are submitting their respective evidence on damages. The final evidentiary hearing on damages will take place on November 6-7, 2014.to remove any alleged obstacles to the progress of the arbitration. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million)648 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($2 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($76 million) from UK HPP and KZT 1.3 billion ($7 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful.
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 4950 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproductsby-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April

62



2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits as well as any subsequently filed similar lawsuits. The Superior Court hasbetween April 2010 and November 2011, and may also ordered that, forstay the present,October 2014 lawsuit. Presently, discovery will proceedis proceeding only in the November 2009 lawsuit and will be limited toon causation

59



and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($327304 million) in the arbitration, plus interest and costs. The evidentiary hearing took place on November 27-December 6, 2013, and January 6-17, 2014. Closing arguments were heard on May 21-22, 2014. The parties are awaiting the Tribunal's award. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($454410 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction inof the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. The Park Administrator subsequently approved a new area for the recovery project. Eletropaulo is currently awaiting the draft of the agreement by the environmental agency, and expects to proceed with the recovery project after reaching agreement with the environmental agency.
In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of São Paulo Federal Court against the Brazilian Regulatory Agency (“ANEEL”), Eletropaulo and all other distribution companies in the State of São Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserted that the distribution companies’ tariffs had been incorrectly calculated by ANEEL, and that the tariffs were required to be corrected from the effective dates of the relevant concession contracts. SOSC asserted that ANEEL erred in May 2010, when the agency corrected the alleged error going forward but declared that the tariff calculations made in the past were correct. Eletropaulo opposed the lawsuit on the ground that it had not wrongfully collected amounts from its customers, as its tariffs had been calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. Subsequently, the lawsuit was transferred to the Federal Court of Belo Horizonte ("FCBH"), which was presiding over similar lawsuits against other distribution companies and ANEEL. In January 2014, the FCBH dismissed the lawsuit against Eletropaulo and the other distribution companies. Incompanies ("January 2014 Decision"). An appeal was filed in May 2014, SOSC appealedbut that decision.appeal was unsuccessful. The January 2014 Decision has become final and unappealable. SOSC's lawsuit will continue against ANEEL. If SOSC ultimately

63



prevails against the agency, it is possible that SOSC may file a new lawsuit against Eletropaulo seeking refunds. Eletropaulo estimates that its liability to customers could be approximately R$855 million ($388 million). Eletropaulo believes it has meritorious defenses and willwould vigorously defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.any such lawsuit.
In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$2.82.86 billion ($1.271.17 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. Eletropaulo believes it has

60



meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$844854 million ($383350 million) as estimated by AES Tietê. AES Tietê has filed an appeal to the Second Instance Administrative Court. No tax is due while the appeal is pending. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas ("Camara") perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its report to date. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has not yet established the procedural schedule for the arbitration.arbitration, but has not yet scheduled the final evidentiary hearing. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assuranceassurances that they will be successful in their efforts.
In April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately KZT 720 million ($4.03.9 million) in damages ("April 2013 Order”). The ED claimed that UK CHP was illegally operating without an emissions permit for 27 days in February-March 2013. In June 2013, the ED filed a lawsuit with the Specialized Interregional Economic Court (the “Economic Court”) seeking to require UK CHP to pay the assessed damages. UK CHP thereafter filed a separate lawsuit with the Economic Court challenging the April 2013 Order and the ED's allegations. In that lawsuit, in August 2013, the Economic Court ruled in UK CHP's favor and required the ED to vacate the April 2013 Order. That ruling was upheld on two intermediate appeals; however,appeals and thereafter the ED maydid not further appeal to the Kazakhstan Supreme Court. The Economic Court also dismissed the lawsuit filed by the ED. UK CHP believes it has meritorious claims and defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurance that it will be successful in its efforts.
In December 2013, AES Changuinola’s EPC Contractor initiated arbitration pursuant to the parties’ EPC Contract and related settlement agreements. The Contractor alleged, among other things, that AES Changuinola failed to make a settlement payment, release retainage, and acknowledge completion of AES Changuinola hydropower facility. In total, the Contractor sought approximately $41 million in damages, plus interest and costs. AES Changuinola denied the claims and asserted counterclaims against the Contractor. In July 2014, the parties settled the dispute.
ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors as previously disclosed in our 2013 Form 10-K under Part 1 — Item 1A. — Risk Factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information regarding purchases made by The AES Corporation of its common stock:
Repurchase Period Total Number of Shares Purchased Average Price Paid Per Share 
Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1)
 Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan
4/1/2014 - 4/30/14 —
 $—
 —
 $191,479,504
5/1/2014 - 5/31/14 1,165,334
 13.73
 1,165,334
 175,481,733
6/1/2014 - 6/30/14 1,140,379
 13.89
 1,140,379
 159,636,730
Total 2,305,713
 $13.81
 2,305,713
  
Repurchase Period Total Number of Shares Purchased Average Price Paid Per Share 
Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1)
 
Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan (2)
7/1/2014 - 7/31/14 —
 $—
 —
 $299,636,730
8/1/2014 - 8/31/14 2,594,646
 14.67
 2,594,646
 261,596,648
9/1/2014 - 9/30/14 4,783,741
 14.57
 4,783,741
 191,963,430
Total 7,378,387
 $—
 7,378,387
  
_____________________________

6164



(1)
(1) See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
(2) The authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans) and/or privately negotiated transactions. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time.
See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
4.1Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014.
   
31.1 Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
  
31.2 Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O’Flynn (filed herewith).
  
32.1 Section 1350 Certification of Andrés Gluski (filed herewith).
  
32.2 Section 1350 Certification of Thomas M. O’Flynn (filed herewith).
  
101.INS XBRL Instance Document (filed herewith).
  
101.SCH XBRL Taxonomy Extension Schema Document (filed herewith).
  
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).
  
101.DEF XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).
  
101.LAB XBRL Taxonomy Extension Label Linkbase Document (filed herewith).
  
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).


6265



SIGNATURES
Pursuant to the 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.

   
THE AES CORPORATION
(Registrant)
        
Date:August 6,November 5, 2014By: 
/s/ THOMAS M. O’FLYNN
     Name: Thomas M. O’Flynn
     Title: Executive Vice President and Chief Financial Officer (Principal Financial Officer)
        
   By: 
 /s/ SHARON A. VIRAG
     Name: Sharon A. Virag
     Title: Vice President and Controller (Principal Accounting Officer)


6366
s in millions)
US $144
 $134
 $287
 $292
 $227
 $208
 $514
 $500
Andes 116
 114
 183
 211
 159
 105
 342
 316
Brazil 82
 90
 168
 144
 15
 98
 182
 242
MCAC 126
 136
 223
 222
 156
 129
 379
 351
EMEA 68
 81
 195
 189
 91
 79
 286
 268
Asia 26
 42
 36
 78
 3
 36
 39
 114
Corp/Other 4
 22
 26
 19
 16
 2
 42
 21
Intersegment Eliminations 3
 (9) (3) 4
 (9) 13
 (12) 17
Total Adjusted Operating Margin 569
 610
 1,115
 1,159
 658
 670
 1,772
 1,829
Noncontrolling Interests Adjustment 243
 277
 501
 490
 118
 259
 620
 749
Derivatives Adjustment 7
 14
 (3) 1
 (9) (2) (12) (1)
Operating Margin $819
 $901
 $1,613
 $1,650
 $767
 $927
 $2,380
 $2,577
Adjusted Pretax Contribution: For a reconciliation of Adjusted PTC to net income from continuing operations, see Note 12 — Segments included in Item 1. — Financial Statements of this Form 10-Q.

35



Adjusted EPS
  Three Months Ended June 30, Six Months Ended June 30, 
Reconciliation of Adjusted Earnings Per Share 2014 2013 2014 2013 
Diluted earnings per share from continuing operations $0.20
 $0.22
 $0.13
 $0.37
 
Unrealized derivative (gains) losses (1)
 (0.02) (0.05) (0.03) (0.03) 
Unrealized foreign currency transaction (gains) losses (2)
 —
 0.04
 0.03
 0.05
 
Disposition/acquisition (gains) losses —
 (0.03)
(3) 
—
 (0.03)
(4) 
Impairment losses 0.09
(5) 
—
 0.26
(6) 
0.05
(7) 
Loss on extinguishment of debt 0.01
(8) 
0.17
(9) 
0.14
(10 
) 
0.21
(11) 
Adjusted earnings per share $0.28
 $0.35
 $0.53
 $0.62
 
  Three Months Ended September 30, Nine Months Ended September 30, 
Reconciliation of Adjusted Earnings Per Share 2014 2013 2014 2013 
Diluted earnings per share from continuing operations $0.67
 $0.23
 $0.81
 $0.61
 
Unrealized derivative (gains) losses (1)
 0.01
 —
 (0.02) (0.04) 
Unrealized foreign currency transaction (gains) losses (2)
 0.06
 (0.02) 0.07
 0.04
 
Disposition/acquisition (gains) losses (0.51)
(3) 
—
 (0.51)
(4) 
(0.03)
(5) 
Impairment losses 0.08
(6) 
0.18
(7) 
0.34
(8) 
0.23
(9) 
Loss on extinguishment of debt 0.06
(10) 
—
 0.20
(11 
) 
0.20
(12) 
Adjusted earnings per share $0.37
 $0.39
 $0.89
 $1.01
 
_____________________________
(1) 
Unrealized derivative (gains) losses were net of income tax per share of $(0.01)$0.00 and $(0.02)$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $(0.01) and $(0.02)$(0.03) in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
(2) 
Unrealized foreign currency transaction (gains) losses were net of income tax per share of $0.00$0.03 and $0.00$(0.01) in the three months ended JuneSeptember 30, 2014 and 2013, and of $0.01$0.04 and $0.01 in the sixnine months ended JuneSeptember 30, 2014 and 2013, respectively.
(3) 
Amount primarily relates to the gain from the sale of the remaining 20%a noncontrolling interest in Cartagena for $20Masinloc of $283 million ($15283 million, or $0.02$0.39 per share, net of income tax per share of $0.01).$0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per

38



share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction.
(4) 
Amount primarily relates to the gain from the sale of a noncontrolling interest in Masinloc of $283 million ($283 million, or $0.39 per share, net of income tax per share of $0.00), the gain from the sale of the UK wind projects of $78 million ($78 million, or $0.11 per share, net of income tax per share of $0.00), the tax benefit of $12 million ($0.02 per share) associated with the agreement executed in September 2014 to sell a noncontrolling interest in our Dominican Republic businesses, and the tax expense of $4 million ($0.01 per share) related to the Silver Ridge Power transaction.
(5)
Amount primarily relates to the gain from the sale of the remaining 20% interest in Cartagena forof $20 million ($1514 million, or $0.02 per share, net of income tax per share of $0.01), the gain from the sale of wind turbines for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00), the gain from the sale of Trinidad for $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00) as well as the gain from the sale of Chengdu, an equity method investment in China forof $3 million ($2 million, or $0.00 per share, net of income tax per share of $0.00).
(5)(6) 
Amount primarily relates to the assetother-than-temporary impairment of our equity method investment at EbuteEntek of $52$18 million ($3412 million, or $0.05$0.02 per share, net of income tax per share of $0.02) and$0.01), the asset impairment at NewfieldEbute of $11$15 million ($6 million, or $0.00 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).
(6)
Amount primarily relates to the goodwill impairments at DPLER of $136 million ($92 million, or $0.13 per share, net of income tax per share of $0.06), at Buffalo Gap of $18 million ($1823 million, or $0.03 per share, net of income tax per sharenoncontrolling interest of $0.00)$1 million and asset impairments at Ebute of $52 million ($34 million, or $0.05 per share, net of income tax per share of $0.02)$(0.01)), at Newfieldand a tax benefit of $11$25 million ($6 million, or $0.000.03 per share, net of income tax per share of $0.00),share) associated with the previously recognized goodwill impairment at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.00) and other-than-temporary impairment of our equity method investment at Silver Ridge of $44 million ($30 million, or $0.04 per share, net of income tax per share of $0.02).DPLER.
(7) 
Amount primarily relates to other-than-temporary impairment of our equity method investment at Elsta of $122 million ($89 million, or $0.12 per share, net of income tax per share of $0.04). Amount also includes asset impairment at Beaver ValleyItabo (San Lorenzo) of $46$15 million ($346 million, or $0.05$0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).
(8) 
Amount primarily relates to the loss on early retirementgoodwill impairments at DPLER of debt$136 million ($117 million, or $0.16 per share, net of income tax per share of $0.03), and at CorporateBuffalo Gap of $13$18 million ($18 million, or $0.03 per share, net of income tax per share of $0.00), and asset impairments at Ebute of $67 million ($57 million, or $0.08 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01), at DPL of $12 million ($8 million, or $0.01 per share, net of income tax per share of $0.01), and at Newfield of $11 million ($6 million, or $0.00 per share, net of noncontrolling interest of $6 million and of income tax per share of $0.00) as well as the other-than-temporary impairments of our equity method investment at Silver Ridge Power of $42 million ($28 million, or $0.04 per share, net of income tax per share of $0.02) and at Entek of $18 million ($12 million, or $0.02 per share, net of income tax per share of $0.01).
(9) 
Amount primarily relates to the loss on early retirementother-than-temporary impairment of debtour equity method investment at CorporateElsta in the Netherlands of $163$122 million ($12189 million, or $0.16$0.12 per share, net of income tax per share of $0.06)$0.04). Amount also includes the asset impairment at Beaver Valley of $46 million ($33 million, or $0.04 per share, net of income tax per share of $0.02), the asset impairment at Itabo (San Lorenzo) of $15 million ($6 million, or $0.01 per share, net of noncontrolling interest of $8 million and of income tax per share of $0.00) as well as the goodwill impairment at Ebute of $58 million ($43 million, or $0.06 per share, net of income tax per share of $0.02).
(10) 
Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $145$43 million ($9925 million, or $0.14$0.03 per share, net of income tax per share of $0.06)$0.03), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $6 million ($3 million, or $0.00 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(11) 
Amount primarily relates to the loss on early retirement of debt at Corporatethe Parent Company of $188 million ($123 million, or $0.17 per share, net of income tax per share of $0.09), at UK wind projects of $18 million ($14 million, or $0.02 per share, net of income tax per share of $0.01) and at Gener of $8 million ($4 million, or $0.01 per share, net of noncontrolling interest of $2 million and of income tax per share of $0.00).
(12)
Amount primarily relates to the loss on early retirement of debt at the Parent Company of $165 million ($123120 million, or $0.16 per share, net of income tax per share of $0.06) and at Masinloc of $43 million ($29 million, or $0.04 per share, net of noncontrolling interest of $3 million and of income tax per share of $0.01).

Operating Margin and Adjusted PTC Analysis
US SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our US SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $144
 $147
 $(3) -2 % $278
 $292
 $(14) -5 %
Noncontrolling Interests Adjustment —
 —
     —
 —
    
Derivatives Adjustment —
 (13)     9
 —
    
Adjusted Operating Margin $144
 $134
 $10
 7 % 287
 292
 $(5) -2 %
Adjusted PTC $80
 $63
 $17
 27 % $155
 $196
 $(41) 21 %
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $222
 $206
 $16
 8% $500
 $498
 $2
 —%
Noncontrolling Interests Adjustment —
 —
     —
 —
    
Derivatives Adjustment 5
 2
     14
 2
    
Adjusted Operating Margin $227
 $208
 $19
 9% 514
 500
 $14
 3%
Adjusted PTC $156
 $132
 $24
 18% $311
 $328
 $(17) 5%
Operating marginMargin for the three months ended JuneSeptember 30, 2014 decreased $3increased $16 million, or 2%8%. This performance was driven primarily by the following businessesbusiness and key operating drivers:
DPL decreased $19 million, primarily due to a $15 million impact from unrealized mark-to-market gains on derivatives in 2013 that did not recur, combined with a decrease in sales volumes, partially offset by an increase in retail rates.
This decrease was partially offset by:
US GenerationOhio increased by $14 million, primarily due to $8regulatory retail rate increases and reduced fuel and purchase power costs of $41 million, relating to the implementationpartially offset by decreased retail sales of the synchronous condensers to provide ancillary services in June 2013 at Southland, $3$25 million due to the completion of

36



the Tait energy storage project at DPL in September 2013,resulting from customer switching and an increase in market prices relating to production at Laurel Mountain of $2 million. mild weather.
Adjusted Operating Margin increased $1019 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin.
Adjusted PTC increased $1724 million driven by a $3$5 million gain recognized from proceeds relatingat Buffalo Gap, due to a bankruptcy settlement at Laurel Mountain,an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest (See Note 1 — General and Summary of Significant Accounting Policies — Noncontrolling Interests included in Item 8. — Financial Statements and Supplementary Data in the Company's 2013 Form 10-K) as well as the increase of $1019 million in Adjusted Operating Margin described above.

39



Operating marginMargin for the sixnine months ended JuneSeptember 30, 2014 decreased $14increased $2 million, or 5%0.4%. This performance was driven primarily by the following businesses and key operating drivers:
DPL decreased $48US Generation increased by $32 million, primarily due to $11 million from increased availability as a result of fewer outages at Hawaii, $7 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 and lower fixed costs at Southland, $8 million at Laurel Mountain due to increased market prices, and $8 million due to the September 2013 completion of the Tait energy storage project; and
IPL in Indiana increased $4 million driven by higher wholesale and retail margin of $13 million, partially offset by higher fixed costs and depreciation of $9 million.
These increases were partially offset by:
DPL decreased $34 million, primarily due to decreases of $31 million attributable to outages and lower gas availability, which resulted in higher purchased power and related costs to supply higher demand from cold weather during the first quarter as well as outages and lower gains on unrealized derivativederivatives of $13 million in the second quarter.
This decrease was The results above were partially offset by:
US Generation increased by $33 million, primarily due to $11 millionimprovements in Q3 resulting from increased availability as a resultretail rates and lower fuel costs of fewer outages at Hawaii, $11 million relating to the implementation of the synchronous condensers to provide ancillary services in June 2013 at Southland, $8 million at Laurel Mountain due to increased market prices relating to production, and $6 million due to the completion 2013 of the Tait energy storage project in September 2013.$16 million.
Adjusted Operating Margin decreased $5increased $14 million for the US SBU due to the drivers above, excluding the impact of unrealized derivative gains and losses. AES owns 100% of its businesses in the US, so there is no adjustment for noncontrolling interests.non-controlling interests within operating margin.
Adjusted PTC decreased $41$17 million driven by net gains of $53 million recognized as a result of the early termination of the PPA and coal supply contract at Beaver Valley during the first quarter of 2013, partially offset by an increase in the Company's share of earnings under the HLBV allocation of noncontrolling interest at Buffalo Gap and Armenia Wind of $10 million, settlements at Laurel Mountain of $6 million, as well as the decreaseincrease of $5$14 million in Adjusted Operating Margin described above.
Andes SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Andes SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $148
 $148
 $—
 —% $239
 $282
 $(43) -15 %
Noncontrolling Interests Adjustment 32
 34
     56
 71
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $116
 $114
 $2
 —% $183
 $211
 $(28) -13 %
Adjusted PTC $104
 $88
 $16
 18% $157
 $169
 $(12) 7 %
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $212
 $134
 $78
 58% $451
 $416
 $35
 8%
Noncontrolling Interests Adjustment 53
 29
     109
 100
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $159
 $105
 $54
 51% $342
 $316
 $26
 8%
Adjusted PTC $120
 $109
 $11
 10% $277
 $278
 $(1) —%
Including the neutralunfavorable impact of foreign currency translation and remeasurement of $3 million, operating margin for the three months ended JuneSeptember 30, 2014 remained flat.increased $78 million, or 58%. This performance was driven primarily by the following businesses and key operating drivers:
Chivor in Colombia increased $55 million as higher inflows resulted in higher generation and spot sales of $44 million as well as higher rates of $6 million.
Gener in Chile increased $30 million due to higher coal and diesel availability of $19 million, and favorable contract and spot prices of $10 million in the SIC market.
This increase was offset by:
Argentina increaseddecreased $6 million driven by higher rates of $17 million related to the Resolution 529 adjustment (retroactive from February 2014), offset by higher fixed costs of $9 million mainly caused by inflation, adjustments.
This increase was offset by:
Gener in Chile decreased $4 million due to lower spot prices and lower margins on Energy Plus contracts at Termoandesgeneration of $8$7 million, and lower contract prices at Norgenerunfavorable foreign exchange rate impact of $5$4 million, partially offset by lower fixed costs from lower maintenancehigher rates of $8 million; and
Chivor in Colombia decreased $2$16 million from higher fixed costs related to the tunnel maintenance, partially offset by higher ancillary services and spot prices.Resolution 529 adjustment.
Adjusted Operating Margin increased $254 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.

37



Adjusted PTC increased $1611 million, driven by the increase of $254 million in Adjusted Operating Margin described above, partially offset by a non-recurring benefit of $20 million from FONINVEMEM III interest income on receivables in 2013 in Argentina and lower realized foreign currency lossesequity in earnings at Guacolda in Chile of $15 million in Chile.$12 million.
Including the unfavorable impact of foreign currency translation and remeasurement of $3$7 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $43increased $35 million, or 15%8%. This performance was driven primarily by the following businesses and key operating drivers:

40



Chivor in Colombia increased $52 million largely driven by significantly higher generation of $51 million resulting in higher spot and contract sales and ancillary services.
This increase was offset by:
Gener in Chile decreased $44$14 million, largely driven by lower availability in the first quarter due primarily to planned outages of $22 million, a reduction of $39$29 million from lower contract prices, spot prices in the SADI and lower Energy Plus margin and lower availability of $6 million; partially offset by the contribution of $10 million from Ventanas IV, which commenced operations in March 2013, and lower fixed costs from lower maintenance and salaries of $9 million;$10 million.
Chivor in ColombiaArgentina decreased $3$4 million driven by higher fixed costs as described above and lower foreign currency exchange rates,of $25 million driven by higher inflation; partially offset by higher prices and AGC sales; and
Argentina increased $3 million driven by higher rates of $17$21 million as a result of the impact of Resolution 529, partially offset by higher fixed costs of $16 million driven by higher inflation adjustment.529.
Adjusted Operating Margin decreased $28increased $26 million for the year due to the drivers above, adjusted for the impact of noncontrolling interests. AES owns 71% of Gener and Chivor and 100% of AES Argentina.
Adjusted PTC decreased $12$1 million, driven by the decreaseincrease of $28$26 million in Adjusted Operating Margin described above, partiallyprimarily offset by higher equity earningsa non-recurring benefit in 2013 from the sale of a transmission line of Guacolda and lower realized foreign currency losses in Chile.FONINVEMEM III interest income on receivables as discussed above.
Brazil SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Brazil SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $270
 $313
 $(43) -14 % $591
 $516
 $75
 15%
Noncontrolling Interests Adjustment 188
 223
     423
 372
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $82
 $90
 $(8) -9 % $168
 $144
 $24
 17%
Adjusted PTC $115
 $78
 $37
 47 % $184
 $120
 $64
 53%
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $44
 $306
 $(262) -86 % $635
 $822
 $(187) -23 %
Noncontrolling Interests Adjustment 29
 208
     453
 580
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $15
 $98
 $(83) -85 % $182
 $242
 $(60) -25 %
Adjusted PTC $—
 $84
 $(84) -100 % $184
 $204
 $(20) 10 %
Including the unfavorable impact of foreign currency translation of $23 million, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreased $43$262 million, or 14%86%. This performance was driven primarily by the following businesses and key operating drivers:
Uruguaiana decreased $39 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation volumes from a temporary restart of operations;
Tietê decreased $12$202 million, driven by unfavorable foreign exchange rates of $16 million anddue to lower hydrology which led to lower generation volumes of $40 million as a result of low water inflows, partially offset byand an increase in energy purchases at higher spot prices of $45 million; andprices;
Eletropaulo decreased $5$29 million due to higher fixed costs of $53$39 million, including higher payroll and pension expense, as well as higher depreciation and unfavorable impact of foreign exchange, partially offset by $59$15 million of higher rates as a result of the July 20132014 tariff adjustmentadjustment; and volume.
These decreases were partially offset by:
Sul increaseddecreased by $13$26 million driven by lower volume and higher volumes from warmer weather of $10 million.fixed costs.
Adjusted Operating Margin decreased $883 million primarily due to the drivers discussed above, adjusted for the impact of noncontrolling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.
Adjusted PTC increasedecreased $3784 million, asdue to the decrease of $883 million in Adjusted Operating Margin as described above was offset by the reversal of a loss contingency related to interest expense of $47 million at Sul that is no longer considered probable.above.

38



Including the unfavorable impact of foreign currency translation of $83 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 increased $75decreased $187 million, or 15%23%. This performance was driven primarily by the following businesses and key operating drivers:
Tietê increased $74decreased $129 million, driven by a net impact of $142 million related to higher sales in the spot market, partially offset by lower contracted volumes of energy sold to Eletropaulo, and unfavorable foreign exchange rates of $61 million;
Eletropaulo increased $24 million, driven by higher tariffs and volume of $99 million, partially offset by unfavorable foreign exchange rates of $17 million and the net impact of $61 million of lower hydrology which led to lower generation and an increase in energy purchases at higher fixed costs of $56 million; and
Sul increased $23 million, due to higher volume of $35 million,prices, partially offset by higher fixed cost expensespot sales in first half of $3 million mainly related to services,2014 due to the stormy weather, and unfavorable foreign exchange rateslower contracted volumes of $5 million.
These increases were partially offset by:energy sold;
Uruguaiana decreased $46$48 million, as a result of the extinguishment of a liability based on a favorable arbitration decision of $53 million in the second quarter of 2013, partially offset by higher generation in 2014 during the period of temporary restart of operations.operations;
Eletropaulo decreased $5 million, driven by higher fixed costs and depreciation of $103 million and unfavorable foreign exchange rates of $16 million, partially offset by higher tariffs and volume of $114 million; and
Sul decreased $3 million, due to higher fixed cost and depreciation expense of $14 million mainly driven by storm related maintenance costs, lower rates of $10 million due to the April 2013 tariff reset, and unfavorable foreign exchange rates of $4 million, partially offset by higher volume of $26 million.
Adjusted Operating Margin increased $24decreased $60 million primarily due to the drivers discussed above, adjusted for the impact of noncontrollingnon-controlling interests. AES owns 16% of Eletropaulo, 46% of Uruguaiana, 100% of Sul and 24% of Tietê.

41



Adjusted PTC increased $64decreased $20 million, driven by the increasedecrease of the $24$60 million in Adjusted Operating Margin described above and higher interest rates and debt, partially offset by the reversal of a loss contingency resulting from a change in estimate related to interest expense of $47 million at Sul that is no longer considered probable, partially offset by higher interest expense, as a result of an increase in interest rates.probable.
MCAC SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our MCAC SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $146
 $149
 $(3) -2 % $235
 $254
 $(19) -7 %
Noncontrolling Interests Adjustment 17
 12
     10
 31
    
Derivatives Adjustment (3) (1)     (2) (1)    
Adjusted Operating Margin $126
 $136
 $(10) -7 % $223
 $222
 $1
 — %
Adjusted PTC $95
 $104
 $(9) -9 % $160
 $160
 $—
 0%
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $176
 $143
 $33
 23% $411
 $397
 $14
 4%
Noncontrolling Interests Adjustment 20
 14
     30
 45
    
Derivatives Adjustment —
 —
     (2) (1)    
Adjusted Operating Margin $156
 $129
 $27
 21% $379
 $351
 $28
 8%
Adjusted PTC $124
 $96
 $28
 29% $284
 $256
 $28
 11%
Including the unfavorable impact of currency translation of $1 million, operating margin for the three months ended JuneSeptember 30, 2014 decreased $3increased $33 million, or 2%23%. This performance was driven primarily by the following businesses and key operating drivers:
Dominican Republic increased $23 million, mainly related to the favorable impact of rates of $29 million due to lower fuel prices, higher PPA prices, and higher prices of gas sales to third parties; and
Panama decreased $8increased $12 million, driven by the Esti tunnel settlement agreement received during the second quarter of 2013 of $31 million, partially offset by a compensation from the government of Panama of $16$13 million related to spot purchases driven by dry hydrological conditions, as well as lower fixed costs of $7 million; and
El Salvador decreased $4 million, due primarily to higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $11 million, mainly related to higher sales due to higher generation of $15 million, as well as higher availability during Q2 2014 of $9 million, partially offset by lower volume of gas sales to third parties of $8 million and higher fuel prices of $5 million.conditions.
Adjusted Operating Margin decreaseincreased $10$27 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC decreaseincreased $928 million, driven by the decreaseincrease of $1027 million in Adjusted Operating Margin as described above.

39



Including the unfavorable impact of currency translation of $2$4 million, operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased $19increased $14 million, or 7%4%. This performance was driven primarily by the following businesses and key operating drivers:
Dominican Republic increased $59 million, mainly related to lower fuel costs of $31 million and higher PPA prices of $12 million, higher availability of $20 million and related lower maintenance expenses of $8 million, partially offset by lower gas sales to third parties of $11 million.
This increase was partially offset by:
Panama decreased $39$27 million, driven by dry hydrological conditions, which resulted in lower generation and higher energy purchases of $45$51 million and the Esti tunnel settlement agreement received during 2013 of $31 million, partially offset by compensation from the government of Panama of $23$36 million related to spot purchases from dry hydrological conditions, as well as lower fixed and other costs during 2014 of $14$17 million; and
El Salvador decreased $18$15 million, due primarily to a one-time unfavorable adjustment to unbilled revenue, as well as higher energy losses and other fixed costs.
This decrease was partially offset by:
Dominican Republic increased $36 million, mainly related to higher availability of $17 million, lower maintenance and other costs of $7 million and higher PPA prices of $12 million.
Mexico increased $5 million, mainly driven by higher availability.
Adjusted Operating Margin increased $1$28 million due to the drivers above, adjusted for the impact of noncontrolling interests and excluding unrealized gains and losses on derivatives. AES owns 89.8% of Changuinola and 49% of its other generation facilities in Panama, 100% of Andres and Los Mina, 50% of Itabo in the Dominican Republic, and a weighted average of 75% of its businesses in El Salvador.
Adjusted PTC remained flat,increased $28 million, driven by the increase of $1$28 million in Adjusted Operating Margin described above, partially offset by lower equity in earnings from the Trinidad business, which was sold in 2013.above.

42



EMEA SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our EMEA SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $77
 $86
 $(9) -10 % $210
 $200
 $10
 5%
Noncontrolling Interests Adjustment 5
 5
     11
 11
    
Derivatives Adjustment (4) —
     (4) —
    
Adjusted Operating Margin $68
 $81
 $(13) -16 % $195
 $189
 $6
 3%
Adjusted PTC $73
 $72
 $1
 1 % $188
 $168
 $20
 12%
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $94
 $85
 $9
 11% $304
 $285
 $19
 7%
Noncontrolling Interests Adjustment 7
 6
     18
 17
    
Derivatives Adjustment 4
 —
     —
 —
    
Adjusted Operating Margin $91
 $79
 $12
 15% $286
 $268
 $18
 7%
Adjusted PTC $79
 $66
 $13
 20% $267
 $234
 $33
 14%
Including the neutral impact of foreign currency translation, operating marginOperating Margin for the three months ended JuneSeptember 30, 2014 decreasedincreased $9 million, or 10%11%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014;
Maritza (Bulgaria)in Bulgaria increased $8 million, driven by better availability of $5 million related to timing of scheduled outages and lower depreciation of $3 million; and
Ebute in Nigeria increased $6 million primarily due to fewer outages of $2 million and lower depreciation of $2 million.
These increases were partially offset by:
Kilroot in the United Kingdom (U.K.) decreased $12$17 million driven by lower availability related to higher scheduled outages.
This decrease was partially offset by:
Kilroot (United Kingdom "U.K.") increased $5 million driven by higherdispatch and rates of $6 million, including income from energy price hedges, and strengthening of the British Pound, partially offset by higher outages of $2$14 million.
Adjusted Operating Margin decreaseincreased $1312 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $113 million, as a result of the decreaseincrease of $1312 million in Adjusted Operating Margin described aboveabove.
Including the unfavorable impact of foreign currency translation of $1 million, operating margin for the nine months ended September 30, 2014 increased $19 million, or 7%. This performance was driven primarily by the following businesses and key operating drivers:
Jordan increased $8 million as the IPP4 Jordan plant commenced operations in July 2014;
Ebute increased $7 million due to fewer outages of $6 million and lower depreciation;
Kazakhstan increased $6 million driven by higher generation volumes and rates of $19 million, partially offset by unfavorable foreign exchange impact of $8 million; and
Wind businesses in the U.K. increased $4 million, driven by higher contributions from Sixpenny Wood, Yelvertoft and Drone Hill, which were sold in August 2014.
These results were partially offset by:
Kilroot decreased $10 million, driven by lower dispatch and higher outages of $19 million, partially offset by higher rates of $11 million, including income from energy price hedges, and favorable foreign exchange impact.
Adjusted Operating Margin increased $18 million due to the drivers above adjusted for non-controlling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $33 million, driven primarily by the increase of $18 million in Adjusted Operating Margin, as well as a reversal of a liability of $18 million in Kazakhstan from the expiration of a statute of limitations for the Republic of Kazakhstan to claim payment from AES.
Including the favorable impact of foreign currency translation of $1 million, operating margin for the six months ended June 30, 2014 increased $10 million, or 5%. This performance was driven primarily by the following businesses and key operating drivers:
Kilroot (U.K.) increased $6 million, driven by higher rates, including income from energy price hedges, favorable FX,AES, partially offset by lower dispatch and higher outages;
Wind businesses (U.K.) increased $4 million, driven primarily by new business generation from Sixpenny Wood and Yelvertoft which commenced commercial operation in July 2013 and higher generation from Drone Hill;

40



Kazakhstan increased $3 million driven by higher generation volumes and rates, partially offset by unfavorable foreign currency; and
Ballylumford (U.K.) increased $2 million, due to higher volumes, partially offset by higher fixed costs.
These results were partially offset by:
Maritza (Bulgaria) decreased $6 million, driven primarily by higher scheduled outages, partially offset by higher rates.
Adjusted Operating Margin increased $6 million due to the drivers above adjusted for noncontrolling interests and excluding unrealized gains and losses on derivatives.
Adjusted PTC increased $20 million, driven primarily by the increase of $6 million in Adjusted Operating Margin, as well as a reversal of a liability in Kazakhstan as described above, partially offset by lower equity in earnings from Turkey.
Asia SBU
The following table summarizes Operating Margin, Adjusted Operating Margin and Adjusted PTC for our Asia SBU for the periods indicated:
  Three Months Ended June 30, Six Months Ended June 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $27
 $45
 $(18) -40 % $37
 $83
 $(46) -55 %
Noncontrolling Interests Adjustment 1
 3
     1
 5
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $26
 $42
 $(16) -38 % $36
 $78
 $(42) -54 %
Adjusted PTC $23
 $40
 $(17) -43 % $31
 $71
 $(40) 56 %
  Three Months Ended September 30, Nine Months Ended September 30,
  2014 2013 $ Change % Change 2014 2013 $ Change % Change
  ($’s in millions)
Operating Margin $12
 $38
 $(26) -68 % $49
 $121
 $(72) -60 %
Noncontrolling Interests Adjustment 9
 2
     10
 7
    
Derivatives Adjustment —
 —
     —
 —
    
Adjusted Operating Margin $3
 $36
 $(33) -92 % $39
 $114
 $(75) -66 %
Adjusted PTC $2
 $30
 $(28) -93 % $33
 $101
 $(68) 67 %

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Operating margin for the three months ended JuneSeptember 30, 2014 decreased by $1826 million, or 40%68%. This performance was driven primarily by the following businesses and key operating drivers:
Masinloc (Philippines)in the Philippines decreased by $17$23 million driven by lower plant availability and related maintenance of $14 million and the net impact of lower spot sales and lower price of spot purchases of $2$18 million; and
Kelanitissa (Sri Lanka)in Sri Lanka decreased by $5$6 million driven by the step down in the contracted PPA price.price and higher outages and maintenance costs.
Adjusted Operating Margin decreased by $16$33 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc.
Adjusted PTC decreased by $17$28 million, driven by the decrease of $16$33 million in Adjusted Operating Margin described above.above, partially offset by the impact of lower proportional interest expense at Masinloc, and OPGC higher equity earnings.
Operating margin for the sixnine months ended JuneSeptember 30, 2014 decreased by $46$72 million, or 55%60%. This performance was driven primarily by the following businesses and key operating drivers:
Masinloc (Philippines)in the Philippines decreased by $41$64 million, driven by $20$33 million due to lower plant availability, an unfavorable impact of $15 million resulting from the market operator's adjustment in the first quarter of 2014 to retrospectively recalculate energy prices related to an unprecedented increase in spot energy prices in November and December 2013, higher fixed costs of $5 million primarily due to maintenance, and net impact of higher contract demand at lower prices and lower spot sales and lower price of spot purchases of $5$4 million; and
Kelanitissa (Sri Lanka)in Sri Lanka decreased by $10$16 million driven by the step down in the contracted PPA price.
Adjusted Operating Margin decreased by $42$75 million due to the drivers above adjusted for the impact of non-controlling interests. AES owns 92%51% of Masinloc after the sell-down in mid-July 2014, and 90% of Kelanitissa. In the comparative period in 2013, AES owned 92% of Masinloc.
Adjusted PTC decreased by $40$68 million, driven by the decrease of $42$75 million in Adjusted Operating Margin described above, partially offset by the impact of lower proportional interest expense at Masinloc due to a 2013 debt refinancing.and gains on foreign currency.
Key Trends and Uncertainties
During the remainder of 2014 and beyond, we expect to face the following challenges at certain of our businesses. Management expects that improved operating performance at certain businesses, growth from new businesses and global cost reduction initiatives may lessen or offset their impact. If these favorable effects do not occur, or if the challenges described below and elsewhere in this section impact us more significantly than we currently anticipate, or if volatile foreign currencies and commodities move more unfavorably, then these adverse factors, a combination of factors, (or other adverse factors unknown to us) may have a material impact on our operating margin, net income attributable to The AES Corporation and cash flows. We continue to monitor our operations and address challenges as they arise. For the risk factors related to our business, see Item 1. — Business and Item 1A. — Risk Factors of the 2013 Form 10-K.
Regulatory
Ohio—As noted in Item 1. — Business - United States— US SBU — Dayton Power & Light Company of the 2013 Form 10-K, an order was issued by the Public Utilities Commission of Ohio ("PUCO") in September 2013 (the “ESP Order”), which states that DP&L’s next ESP begins January 1, 2014 and extends through May 31, 2017.
On March 19, 2014, the PUCO issued a second entry on rehearing ("Entry on Rehearing") which changes some terms of
the ESP order. The Entry on Rehearing shortens the time by which DP&L must divest its generation assets to no later than
January 1, 2016 from May 31, 2017 in the ESP Order. The Entry on Rehearing also terminates the potential extension of the
Service Stability Rider on April 30, 2017 instead of May 31, 2017. In addition, the Entry on Rehearing accelerates DP&L’s
phase-in of the competitive bidding structure to 10% in 2014, 60% in 2015 and 100% in 2016, compared to 10% in 2014, 40%
in 2015, 70% in 2016 and 100% in June 2017 in the ESP Order. Parties, including DP&L, have filed applications for rehearing
on this Commission Order, which were granted in the PUCO’s third entry on rehearing on May 7, 2014.
On June 4, 2014, the PUCO issued a fourth entry on rehearing which reinstated the deadline by which DP&L must divest
its generation assets to January 1, 2017. The Ohio Consumer's Counsel has filed an application for rehearing on this Order,
which was denied by the PUCO. On June 30, 2014, several intervening parties filed a joint motion to stay collection of the Service Stability Rider while appeals are pending. This motion to stay was denied by the PUCO. The Industrial Energy Users of Ohio and the Ohio Consumer's Counsel filed Notices of Appeal of various aspects of the ESP Order and Entries on Rehearing to the Ohio Supreme Court on August 29, 2014 and September 22, 2014, respectively. On September 19, 2014, DP&L filed a Notice of Cross-appeal of the accelerated phase-in of the competitive bidding structure.

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In accordance with the ESP Order, on December 30, 2013, DP&L filed an application with the PUCO stating its plan to transfer or sell its generation assets on or before May 31, 2017. DP&L amended its application on February 25, 2014 and again on May 23, 2014. On September 17, 2014, the PUCO issued a Finding and Order in which it approved of DP&L’s plan to separate its generation assets with minor modifications. Specifically, DP&L’s request to defer costs associated with the Ohio Valley Electric Corporation (OVEC) which are not currently being recovered through existing rates was denied, and DP&L was ordered to transfer environmental liabilities with the generation assets. See Item 1. - — Business -— United States SBU -— Dayton Power & Light Company of the 2013 Form 10-K for further details of the ESP order and the filing to separate generation.
Philippines—In November and December 2013, the Philippines spot market witnessed an unprecedented price spike compared to historical levels. On March 11, 2014, Energy Regulatory Commission ("ERC") declared the market prices from this period void and ordered the market operator to recalculate the prices for all market participants for November and December 2013 billing months. The recalculation of prices based on the load weighted average prices for the first nine months of 2013 resulted in an unfavorable adjustment of approximately $15 million to Masinloc spot sales. The ERC’s review of the motions for reconsideration filed by market participants including Masinloc is on-going. A secondary price cap was established for May and June 2014 and has been extended to mid-August,December, as a temporary measure to mitigate spot price impacts in the market. AtAs of this time the measure is expected to apply temporarilyhas not had a material impact on our business in 2014, in which case the impact may not be material.Philippines. However, if similar measures are implemented on a permanent basis, the impact could be material.
Dominican Republic— In August 2014, the Superintendence of Electricity (Sectoral Regulatory Body of the Electricity Sector), modified the rules for offering primary frequency regulation service, an ancillary service item. The former rules allocated the service to generators based on merit order and those which were the most flexible and could enter the system quickly generally satisfied the supply requirement. The new rule assigns a mandatory minimum margin to all generators which must be provided by own source or through bilateral contracts with other generators who can offer the service, and any additional supply requirement must be allocated using the merit order process. As the AES businesses, Andres and Los Mina, were lower in the merit order they received a majority of the allocation under the former rules. The lower allocation of this service to these units under the new rules will have an impact of lowering the margin from frequency regulation which will be partially offset by higher energy dispatch.
Operational
Sensitivity to Dry Hydrological Conditions

Our hydroelectric generation facilities are sensitive to changes in the weather, particularly the level of water inflows into generation facilities. Throughout 2013 and 2014, dry hydrological conditions in Brazil, Panama, Chile and Colombia have presented challenges for our businesses in these markets. Low rainfall and water inflows caused reservoir levels to be below historical levels, reduced generation output, and increased prices for electricity. If our hydroelectric generation facilities cannot generate sufficient energy to meet contractual arrangements, we may need to purchase energy to fulfill our obligations, which could have a material adverse impact on our results of operations. Some local forecasts suggest continued dry conditions for the remainder of 2014. Once rainfall and water inflows return to normal levels, high market prices and low generation could persist until reservoir levels are fully recovered.
In Brazil, the system operator controls all hydroelectric generation dispatch and reservoir levels, and manages an Energythere is a mechanism called MRE (Energy Reallocation MechanismMechanism) created to share hydrological risk across all generators. If the system of hydroelectric generation facilities generates less than the assured energy of the system, the shortfall is shared among generators, and depending on a generator's contract level, is fulfilled with spot market purchases. We expect the system operator in Brazil to pursue a more conservative reservoir management strategy going forward, including the dispatch of up to 16 GW of thermal generation capacity, which could result in lower dispatch of hydroelectric generation facilities and electricity prices higher than historicalat high levels. During the first and second quarters of 2014, AES Tietê benefited from lower contract levels and captured spot sales at favorable prices. However, AES Tietê has higher contract obligations in the second half of 2014 and may needhas needed to fulfill some of these obligations with spot purchases, so itthey will be sensitive to generation output and spot prices for electricity during this period. Finally, if dry conditions persist in Brazil throughout 2014 and into the next rainy season, from NovemberDecember 2014 to April 2015, there is a risk that the

41

government of Brazil could implement a rationing program in 2015, which could have a material adverse impact on our results of operations and cash flows.
In Panama, dry hydrological conditions continue to reduce generation output from hydroelectric facilities and have increased spot prices for electricity. From March to June 2014, the government of Panama implemented certain energy saving measures designed to reduce demand for electricity during the peak hours by approximately 300 MW, which contributed to water savings in the key hydroelectric dams and lower spot prices. AES Panama has had to purchase energy on the spot market to fulfill its contract obligations when its generation output is below its contract levels, and we expect this trend to continue for the remainder of the year. As authorized on March 31, 2014, the government of Panama agreed to reduce the financial impact of spot electricity purchases and transmission constraints equivalent to a 70MW reduction in contracted capacity for the period

45

2014-2016 by compensating AES Panama for spot purchases up to $40 million in 2014, $30 million in 2015 and $30 million in 2016. Compensation payments recognized through September 30, 2014 were $36 million, of which $12 million are pending to be collected. AES owns 49% of AES Panama. Additionally, as part of our strategy to reduce our reliance on hydrology, AES Panama acquired a 72MW power barge for $26 million, financed with non-recourse debt, in September 2014, which we expect to become operational in the first quarter of 2015.
Taxes
Chilean Tax Reform
On April 1,September 29, 2014, the Chilean government sent to Congress a bill proposingenacted comprehensive tax reforms. The proposed reforms would introducewhich introduced significant changes which, among others, include an increase in theto corporate income tax rate from 20% to 25% over a periodrates, modification of 4 years, the introduction of “Greenshareholder level income tax beginning in 2017, and new “green taxes” primarily over CO2 emissions and from 2017 a shareholder level tax on accrued profits rather than on actual dividends. The potential new legislation is being debatedalso beginning in Congress and could be subject to2017. See Note 17 — Income Taxes in Part I. Item 1. — Financial Statements of this Form 10-Q for further modification in the next several months. Should the bill be approved, the financial impact could be material.information.
Macroeconomic and Political
During the past few years, economic conditions in some countries where our subsidiaries conduct business have deteriorated. Global economic conditions remain volatile and could have an adverse impact on our businesses in the event these recent trends continue.
Argentina — In Argentina, economic conditions are deteriorating, as measured by indicators such as non-receding inflation, diminishing foreign reserves, the potential for continued devaluation of the local currency, and a decline in economic growth. Many of these economic conditions in conjunction with the restrictions to freely access the foreign exchange currency established by the Argentine Government since 2012, have contributed to the development of a limited parallel unofficial foreign exchange market that is less favorable than the official exchange. At JuneSeptember 30, 2014, all transactions at our businesses in Argentina were translated using the official exchange rate published by the Argentine Central Bank. See Note 6 — Financing Receivables in Part I Item 1. — Financial Statements of this Form 10-Q for further information on the long-term receivables. Although our businesses in Argentina have been able to access foreign currency for parts, equipment and equipmentfuel purchases and debt payments when needed, a further weakening of the Argentine Peso and local economic activity could cause significant volatility in our results of operations, cash flows, the ability to pay dividends to the Parent Company, and the value of our assets.
Argentina defaulted on its public debt in 2001, when it stopped making payments on about $100 billion amid a deep economic crisis. In 2005 and 2010, Argentina restructured its defaulted bonds into new securities valued at about 33 cents on the dollar. Between the two transactions, 93% of the bondholders agreed to exchange their defaulted bonds for new bonds. The remaining 7% did not accept the restructured deal. Since then, a certain group of the “hold-out” bondholders have been in judicial proceedings with Argentina regarding payment. More recently, the United States District Court ruled that Argentina would need to make payment to such hold-out bondholders according to the original applicable terms. Despite intense negotiations with the hold-out bondholders through the U.S. District Court appointed Special Master, on July 30, 2014 the parties failed to reach a settlement agreement and consequently (as referred by S&P and Fitch ratings) Argentina fell into a selective default resulting from failure to make interest payments on its Discount Bonds maturing in December 2033. Argentina has expressed thatAlthough this situation remains unresolved, it will attempt to reach a satisfactory settlement agreement to unlock the current situation. This situation has not caused any significant changes that impact our current exposures other than those that are discussed above in regards to the macroeconomics within the country.
Bulgaria—Our investments in Bulgaria rely on offtaker contracts with NEK, the state-owned electricity public supplier and energy trading company. Maritza, a lignite-fired generation facility, has experienced ongoing delays in the collection of outstanding receivables as a result of liquidity issues faced by NEK. In November 2013, Maritza and NEK signed a rescheduling agreement for the overdue receivables as of November 12, 2013. Under the terms of the agreement, NEK paid $70 million of the overdue receivables and agreed to pay the remaining receivables in 13 equal monthly installments beginning December 2013. NEK has made payments according to the schedule through JulySeptember 2014. As of JuneSeptember 30, 2014, Maritza had outstanding receivables of $226 million, representing $43$50 million of current receivables, $30$14 million of the rescheduled receivables not yet due, $85$74 million of receivables overdue by less than 90 days and $69$88 million of receivables overdue by more than 90 days. On July 31, 2014 Maritza entered into a tripartite agreement with NEK and Mini Maritza Iztok EAD

42

(MMI), our fuel supplier, which reduced Maritza's outstanding receivables from NEK by $17.3$17 million through an offset of payables due by Maritza to MMI. Additionally, NEK has agreed to four additional monthly installments totaling $27.6$28 million to be paid equally from August to November, 2014. Maritza has also received payments on outstanding receivables of $14.5 million subsequent to June 30, 2014 which were not under the tripartite agreement. Although Maritza continued to collect overdue receivables during the secondthird quarter of 2014 and thereafter, there continue to be risks associated with collections, which could result in a write-off of the remaining receivables and/or liquidity problems which could impact Maritza's ability to meet its obligations, if the situation around collections were to deteriorate significantly.
In May and June 2014, Bulgaria’s State Energy and Water Regulatory Commission (SEWRC) issued decisions precluding the ability of NEK to pass-through to the regulated market certain costs incurred by NEK pursuant to the PPA with Maritza,

46

which could further impactimpacted NEK's liquidity and its ability to make payments under the PPA. SEWRC also instructed NEK and Maritza to begin negotiating amendments to the PPA, including taking one of Maritza’s units out of the PPA and reducing the price of the remaining unit’s output by 30%. It is unclear whether NEK will abide by its obligations underHowever, SEWRC confirmed that until such negotiations conclude, the PPA or objectis in full force and effect and NEK has not objected to Maritza's invoices going forward.invoices. Maritza has filed appeals and requests for suspension of these SEWRC decisions with the Supreme Administrative Court in Bulgaria.Bulgaria with the first hearing scheduled for the beginning of 2015. In addition, SEWRC announced that it has asked the Directorate-General for Competition of the European Commission (DG Comp) to review NEK's respective PPAs with Maritza and a separate generator pursuant to European state aid rules, and to suspend the PPAs pending the completion of that review. DG Comp has not contacted Maritza about the SEWRC's request to date.
On July 24, 2014, the Government of Bulgaria formally resigned.resigned and the Caretaker Government was appointed by the President. Preliminary Parliamentary Elections are scheduled forwere held on October 5, 2014 to put2014. Eight political parties were elected and are currently discussing the formation of a new government in place. Installation of the new governmentwhich is expected to allow the negotiations to continue in a productive manner. Meanwhile the Caretaker Government requested and received the resignations of the former Chairman and two commissioners of the Regulator. The new leadership approved an end-consumer energy price increase of approximately 10% effective October 1, 2014, which is expected to slightly improve NEK's liquidity. The Caretaker Government also established an Energy Board, which is consultative body comprised of members who have an interest in the energy sector, with the objective to discuss and propose measures to be taken for stabilization of the energy sector. Maritza is a member of the Energy Board.
As a result of any of the foregoing events (including failure by NEK to honor its obligations under the PPA for any reason), we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value (including, without limitation, the value of receivables listed above) and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company. For further information about the risks associated with the Company's investment in Maritza, see the following items in the Company's 2013 Form 10-K: Item 1— Business - EMEA; Item 1A. — Risk Factors of the 2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and Item 7: Management's Discussion & Analysis - Key Risks and Uncertainties.Uncertainties. See Note 8 — Debt included in Part I Item 1. — Financial Statements of this Form 10-Q for further information on current existing debt defaults. Further, Maritza is in litigation related to construction delays and related matters. For further information on the litigation see Part II Item 1. — Legal Proceedings.
Maritza will take all actions necessary to protect its interests, whether through negotiated agreement with NEK or through enforcement of its rights under the PPA. In addition, if necessary, Maritza will defend the PPA in any assessment or proceeding that may be initiated by DG Comp in response to SEWRC's request. As such, as of JuneSeptember 30, 2014, we concluded there is no indicator of an impairment of the long-lived assets in Bulgaria for Maritza, which were $1.4$1.3 billion and total debt of $797$720 million, and Kavarna, which were $280$256 million and total debt of $190$176 million. Therefore, there is no reason to believemanagement believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014.
Puerto Rico— Our subsidiary in Puerto Rico has a long-term PPA with the Puerto Rico Electric Power Authority (“PREPA”), a state-owned entity that supplies virtually all of the electric power consumed in the Commonwealth and generates, transmits and distributes electricity to 1.5 million customers. As a result of macroeconomic challenges in the country, including a seven-year recession, PREPA faces economic challenges including, but not limited to reliance on high cost fuel oil, decline in electricity sales, high customer power rates, high operating costs, past due accounts receivables from government institutions, and very low liquidity along with challenges obtaining financing due to the recent downgrades, and has struggled to honor its payment obligations to electricity generators on a timely basis. As a result, AES Puerto Rico's receivables balance has increased toas of September 30, 2014 is $95 million, outstanding as of June 30, 2014, of which $27$33 million is overdue and days sales outstanding from PREPA has deteriorated, which has caused our business to start to be delayed in our payments to suppliers. Subsequent to JuneSeptember 30, 2014, the overdue receivables of $27$30 million have been collected.
In February 2014, all agencies downgraded the Commonwealth of Puerto Rico and it's public sector companies (PREPA included) to below investment grade. On June 28, 2014, the Governor of Puerto Rico signed into law the Recovery Act, which allows public corporations to adjust their debts in the interest of all creditors, and establishes procedures for the orderly enforcement. With the recent passing of the Recovery Act, the ratings were further reduced. S&PThe downgrade on PREPA has yet to lowerhad a direct impact on AES Puerto Rico's bonds, except for Moody's which rates the Commonwealth's rating butbonds above the state-owned corporation given AES Puerto Rico is expected to do so in the near term.lowest cost producer of electricity. We believe that AES Puerto Rico’s unique position as the lowest cost energy producer and cost-effective alternative for PREPA relative to fuel oil generated power, positions the business well and reduces the probability of negative impacts from a potential PREPA restructuring process. However there can be no assurance as to the final terms of any restructuring or potential impacts on AES Puerto Rico.
If AES Puerto Rico fails to receive payment in accordance with the terms of the PPA with PREPA, its liquidity issues could worsen, which could further impact AES Puerto Rico's ability to meet its obligations. See Item 1A. — Risk Factors of the

47

2013 Form 10-K — “We may not be able to enter into long-term contracts, which reduce volatility in our results of operations” and "We have a significant amount of debt, a large percentage of which is secured, which could adversely affect our business and the ability to fulfill our obligations." As a result of any of the foregoing events, we may face a loss of earnings and/or cash flows from the affected businesses (or be unable to exercise remedies for a breach of the PPA) and may have to provide loans or equity to support affected businesses or projects, restructure them, write down their value and/or face the possibility that these projects cannot continue operations or provide returns consistent with our expectations, any of which could have a material impact on the Company.
Our Puerto Rico business will take all actions necessary to protect its interests, whether through negotiated agreement with PREPA or through enforcement of its rights under the PPA. In October 2014, the Parent Company reached an agreement with an investor in AES Puerto Rico's preferred shares to retire the investment at a fixed redemption value of $52 million. The redemption is expected to be completed by the end of 2014. As the events pertaining to the Recovery Act continue to

43

unfold, we concluded that there is no indicator of an impairment of the long-lived assets in Puerto Rico, which were $620$635 million and total debt of $584 million, and there is no reason to believe$594 million. Therefore, management believes the carrying amount of the asset group was notis recoverable as of JuneSeptember 30, 2014.
If global economic conditions deteriorate further, it could also affect the prices we receive for the electricity we generate or transmit. Utility regulators or parties to our generation contracts may seek to lower our prices based on prevailing market conditions pursuant to PPAs, concession agreements or other contracts as they come up for renewal or reset. In addition, rising fuel and other costs coupled with contractual price or tariff decreases could restrict our ability to operate profitably in a given market. Each of these factors, as well as those discussed above, could result in a decline in the value of our assets including those at the businesses we operate, our equity investments and projects under development and could result in asset impairments that could be material to our operations. We continue to monitor our projects and businesses.
Impairments

Goodwill — Since its annual goodwill impairment test in the fourth quarter of 2013, the Company has been monitoring three reporting units, DP&L, DPLER and Buffalo Gap, as “at risk.” A reporting unit is considered “at risk” when its fair value is not higher than its carrying amount by more than 10%. In the first quarter of 2014, the Company recognized a full goodwill impairment of $136 million at DPLER and a goodwill impairment of $18 million at Buffalo Gap. The Company continues to monitor the remaining goodwill of $10 million at Buffalo Gap and the $316 million goodwill at DP&L. It is possible that the Company may incur goodwill impairment at DP&L, Buffalo Gap or any other reporting unit in future periods if certain events, such as, adverse changes in their business or operating environments occur.
Environmental
The Company is subject to numerous environmental laws and regulations in the jurisdictions in which it operates. The Company expenses environmental regulation compliance costs as incurred unless the underlying expenditure qualifies for capitalization under its property, plant and equipment policies. The Company faces certain risks and uncertainties related to these environmental laws and regulations, including existing and potential greenhouse gas (“GHG”) legislation or regulations, and actual or potential laws and regulations pertaining to water discharges, waste management (including disposal of coal combustion byproducts) and certain air emissions, such as SOsulfur dioxide (SO2), NOnitrogen oxides (NOx), particulate matter (PM)and mercury. Such risks and uncertainties could result in increased capital expenditures or other compliance costs which could have a material adverse effect on certain of our U.S. or international subsidiaries and our consolidated results of operations. For further information about these risks, see Item 1A. —- Risk Factors, “Our“Our businesses are subject to stringent environmental laws and regulations,,” “Our“Our businesses are subject to enforcement initiatives from environmental regulatory agencies,,” and “Regulators,“Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could have a material adverse impact on our consolidated results of operations, financial condition and cash flows”flows” set forth in the Company’s Form 10-K for the year ended December 31, 2013.2013. The following discussion of the impact of environmental laws and regulations on the Company updates the discussion provided in Item 1. —- Business —- Regulatory Matters —- Environmental and Land Use Regulations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 and in Item 2. —- Management's Discussion and Analysis of Financial Condition and Results of Operations —- Key Trends and Uncertainties —- Regulatory —- Environmental of the Company'sCompany’s Quarterly ReportReports on Form 10-Q for the fiscal quarterquarters ended March 31, 2014 and June 30, 2014.
UpdateTax on Greenhouse GasCarbon and Other Emissions Regulationsin Chile
In September 2014, the government of Chile enacted a carbon tax of $5.00 per ton of CO2, as well as taxes on emissions of PM, SO2 and NOx. The United States Environmental Protection Agency (“EPA”) issued proposed rules establishing greenhouse gas (“GHG”) performance standardsamount of the annual tax on PM, SO2 and NOx depends on volume and geographic location of the emissions, among other factors. This tax will be paid annually for existing power plants under Clean Air Act Section 111(d) on June 2, 2014. Under the proposed rule, states would be judged against state-specific carbon dioxide emissions targetsin the previous year, beginning in 2020, with expected total U.S. power section2018 for emissions reductionin 2017. The financial impact to the Company of 30% from 2005 levels by 2030. The proposed rule requires states to submit

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implementation plans to meet the standards set forth in the rule by June 30, 2016, with the possibility of one or two-year extensions under certain circumstances. The proposed rule will be subject to a public comment process during the course of this year, after which time EPA is expected to finalize it by President Obama’s June 1, 2015 deadline. Among other things, the Company's U.S.-based businessesthese taxes could be required to make efficiency improvements to existing facilities. However, it is too soon to determine what the rule, and the corresponding state implementation plans affecting the Company’s U.S.-based businesses, will require once they are finalized, whether they will survive judicial and other challenges, and if so, whether and when the rule and the corresponding state implementations plan would materially impact the Company’s business, operations or financial condition.
In addition,material in October 2013, the U.S. Supreme Court granted certiorari for several cases that address EPA’s authority to issue GHG Prevention of Significant Deterioration (“PSD”) permits under Section 165 of the CAA. In June 2014, the U.S. Supreme Court ruled that EPA had exceeded its statutory authority in issuing the so-called “Tailoring Rule” under Section 165 of the CAA by regulating all sources that emitted GHGs. However, the U.S. Supreme Court also held that EPA could impose GHG Best Achievable Control Technology (“BACT”) requirements for sources already required to implement under PSD for other pollutants. Therefore, if future modifications to the Company's U.S.-based businesses' sources require PSD review for other pollutants, it may also trigger GHG BACT requirements. The EPA has issued guidance on what BACT entails for the control of GHG and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of the U.S. Supreme Court’s ruling and GHG BACT requirements applicable to the operation of the Company's U.S.-based businesses cannot be determined at this time as these businesses are not required to implement BACT until they construct a new major source or make a major modification of an existing major source. However, the cost of compliance could be material.
Update on MATS
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — MATS in the Company's Form 10-K for the year ended December 31, 2013, several lawsuits challenging the Mercury Air Toxics Standards (“MATS”) were filed and consolidated into a single proceeding before the United States Court of Appeals for the District of Columbia Circuit (the “D.C. Circuit”). On April 15, 2014, a three-judge panel of the D.C. Circuit denied the challenges. Twenty-three states and certain industry groups have petitioned the United States Supreme Court to review the decision. We currently cannot predict whether the petition will be granted.
On June 20, 2014, IPL contemporaneously filed a waiver request/alternative complaint with the Federal Energy Regulatory Commission ("FERC") requesting a waiver that will allow IPL to keep 216 MW of reliable capacity available at its Eagle Valley generating station from June 1, 2015 through April 15, 2016. Both of these filings request that the FERC either waive or reform certain requirements of the Midcontinent Independent System Operator, Inc. market tariff for failing to address the specific circumstances resulting from compliance with MATS.
Update on Cooling Water Intake Structures Standards
As further discussed in Item 1. Business — United States Environmental and Land Use Regulations — Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, the Company’s facilities are subject to the U.S. Clean Water Act Section 316(b) rule issued by the EPA which seeks to protect fish and other aquatic organisms by requiring existing steam electric generating facilities to utilize the “Best Technology Available” (“BTA”) for cooling water intake structures. On May 19, 2014, the EPA announced its final standards to protect fish and other aquatic organisms drawn into cooling water systems at large power plants and other industrial facilities. These standards require subject facilities that utilize at least 25% of the withdrawn water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day to choose among seven BTA options to reduce fish impingement. In addition, facilities that withdraw at least 125 million gallons per day for cooling purposes must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. This decision process would include public input as part of permit renewal or permit modification. It is possible this process could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology. Finally, the standards require that new units added to an existing facility are required to reduce both impingement and entrainment that achieves one of two alternatives under national BTA standards for entrainment. It is not yet possible to predict the total impacts of this recent final rule at this time, including any challenges to such final rule and the outcome of any such challenges. However, if additional capital expenditures are necessary, they could be material.periods.

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Update on Environmental Wastewater Requirements
As discussed in Item 1. Business - United States Environmental and Land Use Regulations - Water Discharges in the Company's Form 10-K for the year ended December 31, 2013, certainDP&L is appealing various aspects of the Company’s U.S.-based businesses are subject toa National Pollutant Discharge Elimination System (“NPDES”) permit for J.M. Stuart Station issued by the Ohio EPA. NPDES permits that regulate specific industrial waste waterwastewater and storm water discharges to the watersinto a water of the United States under the FederalU.S. Clean Water Act (“CWA”). In June 2014, the EPA alongAct. It is believed that compliance with the U.S. Army Corpspermit as written will require capital expenses that will be material to DP&L. The cost of Engineers issuedcompliance and the timing of such costs is uncertain and may vary considerably depending on a proposed rule definingcompliance plan that would need to be developed, the waterstype of capital projects that may be necessary, and the uncertainties that may arise in the likely event that permits and approvals from other governmental entities would likely be required to construct and operate any such capital project. DP&L has appealed various aspects of the United States. This rulemakingfinal permit to the Environmental Review Appeals Commission and a hearing has been scheduled for March 2015. The compliance schedule in the potentialfinal permit has been modified to impact all programs underaccommodate the CWA. Expansion of regulated waterways is possible based on initial reviewtiming of the proposal, which may impact several permitting programs. Although we cannot at this time determine the timing or impacthearing. The outcome of compliance with any new regulations, more stringent regulations could have a material impact on our operations and/or consolidated financial results.such appeal is uncertain.
Update on the CSAPR
As furtherAlso as discussed in Item 1. 1. Business —- United States Environmental and Land Use Regulations — CAIR and CSAPR - Water Dischargesin the Company's Form 10-K for the year ended December 31, 2013, in responsethe Indiana Department of Environmental Management (“IDEM”) issued NPDES permits to the D.C. Circuit’s striking down muchIPL Petersburg, Harding Street, and Eagle Valley generating stations, which became effective in October 2012. These permits set new water quality-based levels of acceptable metal effluent water discharges for the EPA’s Clean Air Interstate Rule (“CAIR”)Petersburg and remanding itHarding Street facilities, as well as monitoring and other requirements designed to protect aquatic life, with full compliance with the new metal effluent limitations required by October 2015. IPL received an extension to the EPA, the EPA issued a new rule in July 2011 titled “Federal Implementation Planscompliance deadline through September 2017 for IPL’s Harding Street and Petersburg facilities through agreed orders with IDEM. IPL conducted studies to Reduce Interstate Transport of Fine Particulate Matter and Ozone in 27 States,” which is now referred to as the Cross-State Air Pollution Rule (“CSAPR”). Starting in 2012, the CSAPR would have required significant reductions in SO2 and NOx emissions from covered sources, such as power plants, in certain states in which subsidiaries of the Company operate. Once fully implemented (originally planned for 2014), the rule would requiredetermine what operational changes and/or additional SO2 emission reductions of 73% and additional NOx reductions of 54% from 2005 levels. The CSAPR would be implemented, in part, through a market-based program under which compliance may be achievable through the acquisition and use of new emissions allowances that the EPAequipment will create. The CSAPR contemplates limited interstate and intra-state trading of emissions allowances by covered sources. Initially, the EPA would issue emissions allowances to affected power plants based on state emissions budgets established by the EPA under the CSAPR. The future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time.
Upon petitions for review filed by many states, utilities and other affected parties, the D.C. Circuit vacated the CSAPR in August 2012 and required the EPA to continue administering CAIR pending the promulgation of a valid replacement to the CSAPR. Prior to this decision, the D.C. Circuit had granted a stay of the CSAPR. On April 29, 2014, the United States Supreme Court upheld the CSAPR, reversing the D.C. Circuit Court’s decision to vacate the CSAPR.
It is difficult to predict the steps that will follow this ruling. There remain numerous challenges to the CSAPR that must be addressed, some of which could again result in delay or invalidation of the CSAPR. On June 26, 2014, EPA filed a motion in the D.C. Circuit requesting that the court lift the stay of the CSAPR. EPA also requested that the court extend CSAPR’s compliance deadlines by three years, so that the Phase 1 emissions budgets that were to begin in 2012 would now apply starting in 2015, and the Phase 2 emissions that were to begin in 2014 would apply starting in 2017. The multiple parties to the litigation have filed oppositions to EPA’s motion to lift the stay and all parties have filed motions to govern further proceedings. If the D.C. Circuit grants EPA’s motion, the Company anticipates an increase in capital costs and other expenditures and operational restrictions that would be required to comply with the new limitations. On August 15, 2014, IPL announced its intent to file plans with the IURC to refuel Unit 7 at Harding Street from coal-fired to natural gas. This conversion is part of IPL's overall wastewater compliance plan for its power plants. On October 16, 2014, IPL filed its wastewater compliance plans with the IURC. IPL is seeking approval for a reinstated CSAPR. AtCertificate of Public Convenience and Necessity (CPCN) to install and operate wastewater treatment technologies at its Petersburg and Harding Street plants. If approved, IPL will invest $332 million in these projects to ensure compliance with the wastewater treatment requirements by 2017. IPL expects to recover through its environmental rate adjustment mechanism, operating or capital expenditures related to compliance with these NPDES permit requirements. Recovery of these costs is sought through an Indiana statute that allows for 80% recovery of qualifying costs through a rate adjustment mechanism with the remainder recorded as a regulatory asset to be considered for recovery in the next base rate case proceeding; however, there can be no assurances that IPL will be successful in that regard. In light of the uncertainties at this time, we cannot predict the impact that such rules would haveof these permit requirements on the Company; they could have a material impact on the Company's business,our consolidated results of operations, cash flows, or financial condition, and results of operations.
IPL Unit Retirement and Replacement Generation
As discussed in Item 1. Business — United States Environmental and Land Use Regulations — Unit Retirement and Replacement Generation in the Company's Form 10-K for the year ended December 31, 2013, in April 2013, IPL filed a petition and case-in-chief with the IURC seeking a CPCN to build a 550 MW to 725 MW combined cycle gas turbine (“CCGT”) at its Eagle Valley generating station and to refuel its Harding Street generating station Units 5 and 6 from coal to natural gas (about 100MW each). In May 2014, the IURC issued an order on the CPCN authorizing the refueling project and granting approval to build a 644 to 685 MW CCGT at a total budget of $649 million. The current estimated cost of these projects is $626 million. IPL was granted authority to accrue post in-service allowance for debt and equity funds used during construction and to defer the recognition of depreciation expense of the CCGT and refueling project until such time that we are allowed to collect both a return and depreciation expense on the CCGT and refueling project. The CCGTbut it is expected to be placed into service in April 2017, and the refueling project is expected to be completed in early 2016. The costs to build and operate the CCGT and for the refueling project, other than fuel costs, will not be recoverable by IPL through rates until the conclusion of a base rate case proceeding with the IURC after the assets have been placed in service.material.


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Capital Resources and Liquidity
Overview
As of JuneSeptember 30, 2014, the Company had unrestricted cash and cash equivalents of $1.51.7 billion, of which approximately $15229 million was held at the Parent Company and qualified holding companies, and approximatelycompanies. The Company had $424686 million was held in short term investments, held primarily at subsidiaries. In addition, we had restricted cash and debt service reserves of $1.0 billion967 million. The Company also had non-recourse and recourse aggregate principal amounts of debt outstanding of $15.915.7 billion and $5.85.3 billion, respectively. Of the approximately $2.12.3 billion of our current non-recourse debt, $1.1$1.4 billion was presented as such because it is due in the next twelve months and $1.00.9 billion relates to debt considered in default due to covenant violations. We expect such current maturities will be repaid from net cash provided by operating activities of the subsidiary to which the debt relates or through opportunistic refinancing activity or some combination thereof.
We rely mainly on long-term debt obligations to fund our construction activities. We have, to the extent available at acceptable terms, utilized non-recourse debt to fund a significant portion of the capital expenditures and investments required to construct and acquire our electric power plants, distribution companies and related assets. Our non-recourse financing is designed to limit cross default risk to the Parent Company or other subsidiaries and affiliates. Our non-recourse long-term debt is a combination of fixed and variable interest rate instruments. Generally, a portion or all of the variable rate debt is fixed through the use of interest rate swaps. In addition, the debt is typically denominated in the currency that matches the currency of the revenue expected to be generated from the benefiting project, thereby reducing currency risk. In certain cases, the currency is matched through the use of derivative instruments. The majority of our non-recourse debt is funded by international commercial banks, with debt capacity supplemented by multilaterals and local regional banks.
Given our long-term debt obligations, the Company is subject to interest rate risk on debt balances that accrue interest at variable rates. When possible, the Company will borrow funds at fixed interest rates or hedge its variable rate debt to fix its interest costs on such obligations. In addition, the Company has historically tried to maintain at least 70% of its consolidated

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long-term obligations at fixed interest rates, including fixing the interest rate through the use of interest rate swaps. These efforts apply to the notional amount of the swaps compared to the amount of related underlying debt. Presently, the Parent Company’s only material un-hedged exposure to variable interest rate debt relates to indebtedness under its senior secured credit facility and floating rate senior unsecured notes due 2019. On a consolidated basis, of the Company’s $15.915.7 billion of total non-recourse debt outstanding as of JuneSeptember 30, 2014, approximately $3.94.1 billion bore interest at variable rates that were not subject to a derivative instrument which fixed the interest rate.
In addition to utilizing non-recourse debt at a subsidiary level when available, the Parent Company provides a portion, or in certain instances all, of the remaining long-term financing or credit required to fund development, construction or acquisition of a particular project. These investments have generally taken the form of equity investments or intercompany loans, which are subordinated to the project’s non-recourse loans. We generally obtain the funds for these investments from our cash flows from operations, proceeds from the sales of assets and/or the proceeds from our issuances of debt, common stock and other securities. Similarly, in certain of our businesses, the Parent Company may provide financial guarantees or other credit support for the benefit of counterparties who have entered into contracts for the purchase or sale of electricity, equipment or other services with our subsidiaries or lenders. In such circumstances, if a business defaults on its payment or supply obligation, the Parent Company will be responsible for the business’ obligations up to the amount provided for in the relevant guarantee or other credit support. At JuneSeptember 30, 2014, the Parent Company had provided outstanding financial and performance-related guarantees, indemnities or other credit support commitments to or for the benefit of our businesses, which were limited by the terms of the agreements, of approximately $620 million$1.0 billion in aggregate (excluding those collateralized by letters of credit and other obligations discussed below).
As a result of the Parent Company’s below investment grade rating, counterparties may be unwilling to accept our general unsecured commitments to provide credit support. Accordingly, with respect to both new and existing commitments, the Parent Company may be required to provide some other form of assurance, such as a letter of credit, to backstop or replace our credit support. The Parent Company may not be able to provide adequate assurances to such counterparties. To the extent we are required and able to provide letters of credit or other collateral to such counterparties, this will reduce the amount of credit available to us to meet our other liquidity needs. At JuneSeptember 30, 2014, we had $1 million in letters of credit outstanding, provided under our senior secured credit facility, and $10297 million in cash collateralized letters of credit outstanding outside of our senior secured credit facility. These letters of credit operate to guarantee performance relating to certain project development activities and business operations. During the quarter ended JuneSeptember 30, 2014, the Company paid letter of credit fees ranging from 0.2% to 2.5% per annum on the outstanding amounts.
We expect to continue to seek, where possible, non-recourse debt financing in connection with the assets or businesses that we or our affiliates may develop, construct or acquire. However, depending on local and global market conditions and the unique characteristics of individual businesses, non-recourse debt may not be available on economically attractive terms or at all. If we decide not to provide any additional funding or credit support to a subsidiary project that is under construction or has

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near-term debt payment obligations and that subsidiary is unable to obtain additional non-recourse debt, such subsidiary may become insolvent, and we may lose our investment in that subsidiary. Additionally, if any of our subsidiaries lose a significant customer, the subsidiary may need to withdraw from a project or restructure the non-recourse debt financing. If we or the subsidiary choose not to proceed with a project or are unable to successfully complete a restructuring of the non-recourse debt, we may lose our investment in that subsidiary.
Many of our subsidiaries depend on timely and continued access to capital markets to manage their liquidity needs. The inability to raise capital on favorable terms, to refinance existing indebtedness or to fund operations and other commitments during times of political or economic uncertainty may have material adverse effects on the financial condition and results of operations of those subsidiaries. In addition, changes in the timing of tariff increases or delays in the regulatory determinations under the relevant concessions could affect the cash flows and results of operations of our businesses.
As of JuneSeptember 30, 2014, the Company had approximately $258246 million and $3924 million of accounts receivable related to certain of its generation businesses in Argentina and the Dominican Republic and its utility businesses in Brazil classified as “Noncurrent assets — other” and “Current assets — Accounts receivable,” respectively. The noncurrent portion primarily consists of accounts receivable in Argentina that, pursuant to amended agreements or government resolutions, have collection periods that extend beyond JuneSeptember 30, 2014, or one year from the latest balance sheet date. The majority of Argentinian receivables have been converted into long-term financing for the construction of power plants. See Note 6 — Financing Receivables included in Part I Item 1. — Financial Statements of this Form 10-Q and Item 1. — Business — Regulatory Matters — Argentina included in the 2013 Form 10-K for further information.
Consolidated Cash Flows
During the sixnine months ended JuneSeptember 30, 2014,, cash and cash equivalents decreaseincreased $127$28 million to $1.5$1.7 billion. The decreaseincrease in cash and cash equivalents was due to $453 million1.2 billion of cash provided by operating activities, $391364 million of cash used

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in investing activities, $250844 million of cash used in financing activities, an unfavorable effect of foreign currency exchange rates on cash of $1455 million and a $75 million decrease in cash of discontinued and held-for-sale businesses.
Operating Activities — Net cash provided by operating activities decreased $732824 million to $453 million during the six months endedJune 30, 2014 compared to $1.2 billion during the sixnine months ended JuneSeptember 30, 2014 compared to $2 billion during the nine months endedSeptember 30, 2013. This performance was driven primarily by the following SBUs and key operating activities:
Brazil — a decrease of $505 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes;
MCAC — a decrease of $179 million at our generation businesses primarily due to higher working capital requirements; and
EMEA — a decrease of $94 million primarily due to higher working capital requirements.
OperatingNet cash flow forprovided by operating activities was $1.2 billion during the sixnine months ended JuneSeptember 30, 2014. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization, impairment expenses and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $1 billion in operating assets and liabilities. This net use of cash forwithin operating activities of $1 billion was primarily due to the following:
an increase of $316494 million in accounts receivable primarily related to higher sales at Eletropaulo, Sul and Alicura and lower collections at Maritza;
an increase of $439 million in other assets primarily related to increased regulatory assets at Eletropaulo and Sul resulting from higher priced energy purchases recoverable through future tariffs;
an increase of $312 million in accounts receivable primarily related to higher sales at Sul, Alicura and Gener, return of operations at Uruguaiana in March 2014 and lower collections at Maritza;
a decrease of $194 million in accounts payable and other current liabilities primarily at Eletropaulo relating to a decrease in regulatory liabilities;
a decrease of $176239 million in net income tax and other tax payables primarily related to payments of income taxes exceeding accruals for the 2014 tax liability.liability; partially offset by
an increase of $319 million in other liabilities primarily related to an increase in regulatory liabilities at Eletropaulo and Sul partially offset by reduced pension contributions at IPL and payments for share-based compensation issuance tax and derivative termination at the Parent Company.
Net cash provided by operating activities was $1.22.0 billion during the sixnine months ended JuneSeptember 30, 2013. Operating cash flow resulted primarily from the net income adjusted for non-cash items, principally depreciation and amortization and loss on extinguishment of debt, partially offset by a net use of cash for operating activities of $310255 million in operating assets and liabilities. This net use of cash forwithin operating activities of $310$255 million was primarily due to:
a decrease of $252$578 million in accounts payable and other current liabilities primarily at Eletropaulo and Sul due to lower costs and a decrease in regulatory liabilities and a decrease in value added taxes payables due to the lower tariff in 2013 andas well as at Uruguaiana primarily related to the extinguishment of a liability based on a favorable arbitration decision;
an increase of $147$149 million in other assets primarily due to an increase in noncurrent regulatory assets at Eletropaulo and Sul, resulting from higher priced energy purchases which are recoverable through future tariffs;
partially offset by
a decrease of $134$403 million in net income taxprepaid expenses and other tax payablescurrent assets primarily from payment of income taxes exceeding accrualsdue to a decrease in current regulatory assets, for the tax liability on 2013 income, partially offset by an accrualrecovery of indirect taxes in Brazil; partially offset by
prior-period tariff cycle energy purchases and transportation costs at Eletropaulo and Sul; and
a decrease of $191$135 million in accounts receivable primarily duerelated to lower tariffs in 2013 at Eletropaulo and higher collections combined with lower tariffs and reduced consumption at Sul, partially offset by lower collections at Maritza.

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The net decrease of cash flows from operating activities of $732 million for the six months endedJune 30, 2014 compared to the six months endedJune 30, 2013 was primarily the result of the following:
Brazil — a decrease of $442 million primarily at Eletropaulo and Sul due to higher prices of energy purchases as well as higher taxes and interest on debt.
US — a decrease of $160 million primarily due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating results and higher working capital requirements at DPL.
MCAC — a decrease of $154 million at our generation businesses primarily due to higher working capital requirements.
Investing Activities — Net cash used in investing activities was $391364 million during the sixnine months ended JuneSeptember 30, 2014 primarily attributable to the following:
Capital expenditures of $908 million1.4 billion consisting of $536$789 million of growth capital expenditures and $372$600 million of maintenance and environmental capital expenditures. Growth capital expenditures primarily included amounts at Gener of $250$303 million, Eletropaulo of $83$125 million,Vietnam Mong Duong of $45$72 million, Jordan of $71 million, IPL of $61 million and Jordan $38Sul of $35 million. Maintenance and environmental capital expenditures primarily included amounts at IPL of $105$178 million, Eletropaulo of $42$73 million, Tietê of $40$64 million, Gener of $50 million, DPL of $48 million and DPLSul of $32 million.$41 million;
Acquisitions, net of cash acquired of $728 million consisted of an acquisition at Gener in the second quarter for the remaining 50% interest in our equity investment in Guacolda, of which 50% less one share was subsequently sold during the same quarter. See Note 7 — Investment in and Advances to Affiliates in Item 1. — Financial Statements of this Form 10-Q for further information. These amounts wereinformation; partially offset by
Proceeds from the sale of businesses of $890 million with$1.7 billion including $730 million at Gener related to the sale of 50% less one share of our interest in Guacolda, $443 million for the sale of 45% of our equity interest in Masinloc, $179 million related to the the sale of AES’ interest in Silver Ridge Power’s assets in Bulgaria, France, Greece, India and $160the United States and $156 million from the sale of our businessesbusiness in Cameroon,Cameroon; and

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Decreases in restricted cash, debt service reserves and other assets of $162 million including amounts at the USParent Company of $66 million, Maritza of $44 million and India; and
SalesAlto Maipo of short-term investments, net of purchases of $273 million primarily in Brazil.$37 million.
Net cash used in investing activities was $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:
Capital expenditures of $866 million$1.3 billion consisting of $454$690 million of growth capital expenditures and $412$640 million of maintenance and environmental capital expenditures. Growth capital expenditures included amounts at Eletropaulo of $138$188 million, Gener of $81$166 million, Jordan of $54$95 million, Sul of $44$57 million, Sixpenny WoodDPL of $22$28 million, Mong Duong of $19$27 million, Yelvertoft of $20 million, Kribi of $17 million and YelvertoftAltai of $19$16 million. Maintenance and environmental capital expenditures included amounts at IPALCOIPL of $87$164 million, Eletropaulo of $72$103 million, DPL of $63 million, Gener of $47$61 million, DPLTietê of $46$53 million, Sul of $39$50 million, Altai of $21 million and Itabo of $15 million;
Purchase of short-term investments, net of sales of $263 million including amounts at Eletropaulo of $212 million, Sul of $32 million and Tietê of $30$29 million; partially offset by
Proceeds from the sale of business, net of cash sold of $135$167 million including $113 million for the sale of the Ukraine businesses, $31 million for the sale of our 10% equity interest in Trinidad and $24 million for the sale of our remaining interest in Cartagena.

Net cash used in investing activities decreased $315903 million to $391364 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in investing activities of $706 million1.3 billion during the sixnine months ended JuneSeptember 30, 2013. This net decrease was primarily due to an increase in proceeds from the sale of business, net of cash sold of $1.5 billion, a decrease in purchases of short-term investments, net of sales of $343212 million, partially offset by an increase in acquisitions of $725 million.
Financing Activities — Net cash used in financing activities was $250844 million during the sixnine months ended JuneSeptember 30, 2014. This was primarily attributable to the following:
Payments for financed capital expenditures of $312 million, primarily at Mong Duong with $272 million in payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to minority interests of $197 million primarily at Tietê with $109 million; and
Repayments of recourse and non-recourse debt of $3.03.7 billion including amounts at the Parent Company of $1.7$2 billion, Gener of $853$905 million, Tietê of $132 million, Maritza of $65 million, Shady Point of $52 million, Puerto Rico of $51 million and Puerto Rico$114 million related to the UK Wind sale;
Distributions to noncontrolling interests of $42$377 million including amounts at Tietê of $188 million, Brasiliana Energia of $65 million, Gener of $35 million and Buffalo Gap of $33 million;
Payments for financed capital expenditures of $360 million primarily at Mong Duong of $272 million; partially offset by
Issuances of recourse and non-recourse debt of $3.23.8 billion, including new issuances at the Parent Company of $1.5 billion, Gener of $700 million, Mong Duong of $298 million, Eletropaulo of $253 million, Cochrane of $173 million, IPL of $130 million and Tietê of $129 million; and a draw down under construction loan facility at Mong Duong of $272 million.
Net cash used in financing activities was $799635 million during the sixnine months ended JuneSeptember 30, 2013. This was primarily attributable to the following:

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Payments for financed capital expenditures of $257 million, primarily at Mong Duong for payments to the contractors, which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $211 million included amounts at Tietê of $98 million, Brasiliana of $34 million, Buffalo Gap of $25 million, and Gener of $18 million;
Payments for financing fees of $127 million included amounts at Cochrane of $41 million, Eletropaulo of $25 million, and Mong Duong of $13 million; and
Repayments of recourse and non-recourse debt of $3.4$3.5 billion primarilyincluded amounts at the Parent Company of $1.2 billion, Masinloc of $546 million, DPL of $425 million, Tietê of $396 million, El Salvador of $301 million, IPL of $110 million, Warrior Run of $87$93 million, Puerto Rico of $52$65 million, Maritza of $57 million, Sonel of $46 million and Sul of $37$40 million;
Payments for financed capital expenditures of $436 million, primarily at Mong Duong for payments to the contractors which took place more than three months after the associated equipment was purchased or work performed;
Distributions to noncontrolling interests of $385 million included amounts at Tietê of $154 million, Brasiliana Energia of $96 million, Gener of $39 million and MaritzaBuffalo Gap of $29$19 million;
Payments for financing fees of $148 million included amounts at Cochrane of $42 million, Eletropaulo of $25 million, Mong Duong of $20 million and the Parent Company of $17 million; partially offset by
Issuances of recourse and non-recourse debt of $3.1$3.8 billion,, including amounts at the Parent Company for $750 million, DPL of $645 million, Masinloc of $500 million, Tietê of $496 million, Mong Duong of $339 million, El Salvador of $310 million, Mong Duong of $210 million, DPL of $200 million, IPL of $170 million, Sul of $150 million, Jordan of $138 million, Cochrane of $82$120 million,Warrior Run of $74 million and Kribi of $63 million; and
Contributions from noncontrolling interests of $157 million including amounts at Mong Duong of $55 million, Alto Maipo of $50 million and JordanCochrane of $61$34 million.
Net cash used in financing activities decreasedincreased $549209 million to $250844 million during the sixnine months ended JuneSeptember 30, 2014 compared to net cash used in financing activities of $799635 million during the sixnine months ended JuneSeptember 30, 2013. This net decreaseincrease was primarily due to a decreasean increase in the repayments of recourse and non-recourse debt of $363 million and an increase in the issuance of recourse and non-recourse debt of $102162 million.

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Proportional Free Cash Flow (a non-GAAP measure)
We define Proportional Free Cash Flow as cash flows from operating activities less maintenance capital expenditures (including non-recoverable environmental capital expenditures), adjusted for the estimated impact of noncontrolling interests. The proportionate share of cash flows and related adjustments attributable to noncontrolling interests in our subsidiaries comprise the proportional adjustment factor presented in the reconciliation below.
We exclude environmental capital expenditures that are expected to be recovered through regulatory, contractual or other mechanisms. An example of recoverable environmental capital expenditures is IPL's investment in MATS-related environmental upgrades that are recovered through a tracker. See Item 1. Business— US SBU — IPALCO — Environmental Matters in the 2013 Form 10-K for details of these investments.
The GAAP measure most comparable to proportional free cash flow is cash flows from operating activities. We believe that proportional free cash flow better reflects the underlying business performance of the Company, as it measures the cash generated by the business, after the funding of maintenance capital expenditures, that may be available for investing or repaying debt or other purposes. Factors in this determination include the impact of noncontrolling interests, where AES consolidates the results of a subsidiary that is not wholly-owned by the Company.
The presentation of free cash flow has material limitations. Proportional free cash flow should not be construed as an alternative to cash from operating activities, which is determined in accordance with GAAP. Proportional free cash flow does not represent our cash flow available for discretionary payments because it excludes certain payments that are required or to which we have committed, such as debt service requirements and dividend payments. Our definition of proportional free cash flow may not be comparable to similarly titled measures presented by other companies

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  Three months ended June 30, Six months ended June 30,
  2014 2013 2014 2013
  (in millions)
Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below:        
Maintenance Capital Expenditures $152
 $174
 $289
 $360
Environmental Capital Expenditures 77
 42
 111
 73
Growth Capital Expenditures 414
 354
 820
 690
Total Capital Expenditures $643
 $570
 $1,220
 $1,123
Consolidated        
Net cash provided by operating activities $232
 $567
 $453
 $1,185
Less: Maintenance Capital Expenditures, net of reinsurance proceeds 152
 174
 289
 360
Less: Non-recoverable Environmental Capital Expenditures 25
 26
 36
 47
Free Cash Flow $55
 $367
 $128
 $778
Reconciliation of Proportional Operating Cash Flow        
Net cash provided by operating activities $232
 $567
 $453
 $1,185
Less: Proportional Adjustment Factor (1)
 64
 263
 44
 367
Proportional Operating Cash Flow $168
 $304
 $409
 $818
Proportional        
Proportional Operating Cash Flow $168
 $304
 $409
 $818
Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1)
 102
 121
 206
 258
Less: Proportional Non-recoverable Environmental Capital Expenditures (1)
 19
 18
 27
 34
Proportional Free Cash Flow $47
 $165
 $176
 $526
  Three months ended September 30, Nine months ended September 30,
  2014 2013 2014 2013
  (in millions)
Calculation of Maintenance Capital Expenditures for Free Cash Flow Reconciliation Below:        
Maintenance Capital Expenditures $169
 $166
 $458
 $526
Environmental Capital Expenditures 62
 72
 172
 145
Growth Capital Expenditures 298
 405
 1,119
 1,095
Total Capital Expenditures $529
 $643
 $1,749
 $1,766
Consolidated        
Net cash provided by operating activities $763
 $855
 $1,216
 $2,040
Less: Maintenance Capital Expenditures, net of reinsurance proceeds 169
 166
 458
 526
Less: Non-recoverable Environmental Capital Expenditures 16
 22
 52
 69
Free Cash Flow $578
 $667
 $706
 $1,445
Reconciliation of Proportional Operating Cash Flow        
Net cash provided by operating activities $763
 $855
 $1,216
 $2,040
Less: Proportional Adjustment Factor (1)
 208
 327
 251
 694
Proportional Operating Cash Flow $555
 $528
 $965
 $1,346
Proportional        
Proportional Operating Cash Flow $555
 $528
 $965
 $1,346
Less: Proportional Maintenance Capital Expenditures, net of reinsurance proceeds (1)
 116
 114
 322
 372
Less: Proportional Non-recoverable Environmental Capital Expenditures (1)
 12
 17
 39
 51
Proportional Free Cash Flow $427
 $397
 $604
 $923
(1) The proportional adjustment factor, proportional maintenance capital expenditures (net of reinsurance proceeds), and proportional non-recoverable environmental capital expenditures are calculated by multiplying the percentage owned by non-controlling interests for each entity by its corresponding consolidated cash flow metric and adding up the resulting figures. For example, the Company owns approximately 70% of AES Gener, its subsidiary in Chile. Assuming a consolidated net cash flow from operating activities of $100 from AES Gener, the proportional adjustment factor for AES Gener would equal approximately $30 (or $100 x 30%). The Company calculates the proportional adjustment factor for each consolidated business in this manner and then adds these amounts together to determine the total proportional adjustment factor used in the reconciliation. The proportional adjustment factor may differ from the proportion of income attributable to non-controlling interests as a result of (a) non-cash items which impact income but not cash and (b) AES’ ownership interest in the subsidiary where such items occur.
Proportional Free Cash Flow for the three months ended JuneSeptember 30, 2014 compared to the three months ended JuneSeptember 30, 2013 increased $30 million, driven by higher Proportional Operating Cash Flow and lower Proportional Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by increases from the following SBUs and key operating drivers:
US — driven by higher operating cash flow at the US Utilities driven by lower working capital requirements and higher earnings; and
Brazil — driven by Sul due to higher collections, partially offset by higher energy purchases and higher tax payments.
These increases were partially offset by decreases at:

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Asia — driven by Masinloc due to lower earnings and higher working capital requirements;
EMEA — driven by lower results for Wind entities driven by sale of UK Wind assets, sold in August 2014, and lower collections at Kavarna in Bulgaria as well as Kilroot in the U.K. driven by lower earnings;
MCAC — driven by higher working capital requirements as a result of lower collections and timing of inventory in the Dominican Republic.
Proportional Free Cash Flow for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 decreased $118$319 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance and Non-recoverable Environmental Capital Expenditures. This performance was driven primarily by decreasesincreases from the following SBUs and key operating drivers:
MCAC — due todriven by higher working capital requirements in the Dominican Republic;Republic and Panama;
Brazil — driven by higher pricesprice of energy purchases as well asand higher taxes and interest on debt at Eletropaulo and Sul.Sul; and
These decreases were partially offset by an increase at:
CorpEMEA — driven by lower interest payments.
Proportional Free Cash Flow for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 decreased $350 million, driven by lower Proportional Operating Cash Flow, partially offset by lower Proportional Maintenance Capital Expenditures. This performance was driven primarily by decreases from the following SBUs and key operating drivers:
Brazil — driven by higher prices of energy purchases as well as higher taxes and interest on debt at Eletropaulo and Sul;
MCAC — due to higher working capital requirements in the Dominican Republic; and
US — due to proceeds from the PPA termination at Beaver Valley in January 2013 and lower operating resultsmargins and higher working capital requirementsin the U.K. and lower collections at DPL, partially offset by lower proportional maintenance capital expenditures.Maritza and Kavarna in Bulgaria.
Parent Company Liquidity
The following discussion of Parent Company Liquidity has been included because we believe it is a useful measure of the liquidity available to The AES Corporation, or the Parent Company, given the non-recourse nature of most of our indebtedness. Parent Company Liquidity as outlined below is a non-GAAP measure and should not be construed as an alternative to cash and cash equivalents which are determined in accordance with GAAP as a measure of liquidity. Cash and cash equivalents are disclosed in the condensed consolidated statements of cash flows. Parent Company Liquidity may differ from similarly titled measures used by other companies.
The principal sources of liquidity at the Parent Company level are:

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dividends and other distributions from our subsidiaries, including refinancing proceeds;
proceeds from debt and equity financings at the Parent Company level, including availability under our credit facilities; and
proceeds from asset sales.
Cash requirements at the Parent Company level are primarily to fund:
interest;
principal repayments of debt;
acquisitions;
construction commitments;
other equity commitments;
common stock repurchases;
taxes;
Parent Company overhead and development costs; and
dividends on common stock.
The Company defines Parent Company Liquidity as cash available to the Parent Company plus available borrowings under existing credit facilities. The cash held at qualified holding companies represents cash sent to subsidiaries of the Company domiciled outside of the U.S. Such subsidiaries have no contractual restrictions on their ability to send cash to the Parent Company. Parent Company Liquidity is reconciled to its most directly comparable U.S. GAAP financial measure, “cash and cash equivalents,” at the periods indicated as follows:
Parent Company Liquidity June 30, 2014 December 31, 2013
  (in millions)
Consolidated cash and cash equivalents $1,515
 $1,642
Less: Cash and cash equivalents at subsidiaries 1,500
 1,510
Parent and qualified holding companies’ cash and cash equivalents 15
 132
Commitments under Parent credit facilities 800
 800
Less: Borrowings under the credit facilities (120) —
Less: Letters of credit under the credit facilities (1) (1)
Borrowings available under Parent credit facilities 679
 799
Total Parent Company Liquidity $694
 $931
Parent Company Liquidity September 30, 2014 December 31, 2013
  (in millions)
Consolidated cash and cash equivalents $1,670
 $1,642
Less: Cash and cash equivalents at subsidiaries 1,441
 1,510
Parent and qualified holding companies’ cash and cash equivalents 229
 132
Commitments under Parent credit facilities 800
 800
Less: Letters of credit under the credit facilities (1) (1)
Borrowings available under Parent credit facilities 799
 799
Total Parent Company Liquidity $1,028
 $931

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The Company paid a dividend of $0.05 per share to its common stockholders during the three months ended JuneSeptember 30, 2014. While we intend to continue payment of dividends and believe we will have sufficient liquidity to do so, we can provide no assurance we will be able to continue the payment of dividends.
While we believe that our sources of liquidity will be adequate to meet our needs for the foreseeable future, this belief is based on a number of material assumptions, including, without limitation, assumptions about our ability to access the capital markets (see Key Trends and Uncertainties and Global Economic Considerations in this Item 2), the operating and financial performance of our subsidiaries, currency exchange rates, power market pool prices, and the ability of our subsidiaries to pay dividends. In addition, our subsidiaries’ ability to declare and pay cash dividends to us (at the Parent Company level) is subject to certain limitations contained in loans, governmental provisions and other agreements. We can provide no assurance that these sources will be available when needed or that the actual cash requirements will not be greater than anticipated. We have met our interim needs for shorter-term and working capital financing at the Parent Company level with our senior secured credit facility. See Item 1A. — Risk Factors “The, “The AES Corporation is a holding company and its ability to make payments on its outstanding indebtedness, including its public debt securities, is dependent upon the receipt of funds from its subsidiaries by way of dividends, fees, interest, loans or otherwise.otherwise.” of the Company’s 2013 Form 10-K.
Various debt instruments at the Parent Company level, including our senior secured credit facilities, contain certain restrictive covenants. The covenants provide for, among other items:

limitations on other indebtedness, liens, investments and guarantees;
limitations on dividends, stock repurchases and other equity transactions;
restrictions and limitations on mergers and acquisitions, sales of assets, leases, transactions with affiliates and off-balance sheet and derivative arrangements;
maintenance of certain financial ratios; and

52



financial and other reporting requirements.
As of JuneSeptember 30, 2014, the Parent Company was in compliance with these covenants.
Non-Recourse Debt
While the lenders under our non-recourse debt financings generally do not have direct recourse to the Parent Company, defaults thereunder can still have important consequences for our results of operations and liquidity, including, without limitation:

reducing our cash flows as the subsidiary will typically be prohibited from distributing cash to the Parent Company during the time period of any default;
triggering our obligation to make payments under any financial guarantee, letter of credit or other credit support we have provided to or on behalf of such subsidiary;
causing us to record a loss in the event the lender forecloses on the assets; and
triggering defaults in our outstanding debt at the Parent Company.
For example, our senior secured credit facilities and outstanding debt securities at the Parent Company include events of default for certain bankruptcy related events involving material subsidiaries. In addition, our revolving credit agreement at the Parent Company includes events of default related to payment defaults and accelerations of outstanding debt of material subsidiaries.
Some of our subsidiaries are currently in default with respect to all or a portion of their outstanding indebtedness. The total non-recourse debt classified as current in the accompanying condensed consolidated balance sheet amounts to $2.12.3 billion. The portion of current debt related to such defaults was $1.00.9 billion at JuneSeptember 30, 2014, all of which was non-recourse debt related to two subsidiaries — Maritza and Kavarna.
None of the subsidiaries that are currently in default are subsidiaries that met the applicable definition of materiality under AES’s corporate debt agreements as of JuneSeptember 30, 2014 in order for such defaults to trigger an event of default or permit acceleration under AES’s indebtedness. However, as a result of additional dispositions of assets, other significant reductions in asset carrying values or other matters in the future that may impact our financial position and results of operations or the financial position of the individual subsidiary, it is possible that one or more of these subsidiaries could fall within the definition of a “material subsidiary” and thereby upon an acceleration trigger an event of default and possible acceleration of the indebtedness under the Parent Company’s outstanding debt securities. A material subsidiary is defined in the Company's senior secured revolving credit facility as any business that contributed 20% or more of the Parent Company's total cash distributions from businesses for the four most recently completed fiscal quarters. As of JuneSeptember 30, 2014, none of the defaults listed above individually or in the aggregate results in or is at risk of triggering a cross-default under the recourse debt of the Company.

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Critical Accounting Policies and Estimates
The condensed consolidated financial statements of AES are prepared in conformity with U.S. GAAP, which requires the use of estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company’s significant accounting policies are described in Note 1 — General and Summary of Significant Accounting Policies to the consolidated financial statements included in our 2013 Form 10-K. The Company’s critical accounting estimates are described in Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2013 Form 10-K. An accounting estimate is considered critical if the estimate requires management to make an assumption about matters that were highly uncertain at the time the estimate was made, different estimates reasonably could have been used, or if changes in the estimate that would have a material impact on the Company’s financial condition or results of operations are reasonably likely to occur from period to period. Management believes that the accounting estimates employed are appropriate and resulting balances are reasonable; however, actual results could differ from the original estimates, requiring adjustments to these balances in future periods. The Company has reviewed and determined that those policiesthese remain the Company’sas critical accounting policies as of and for the sixnine months ended JuneSeptember 30, 2014.
During the third quarter of 2014, the following additional critical accounting estimate was employed with respect to the Company's sales of noncontrolling interests:
Sales of Noncontrolling Interests
The accounting for a sale of noncontrolling interests under the accounting standards depends on whether the sale is considered to be a sale of in-substance real estate (as opposed to an equity transaction), where the gain (loss) on sale would be recognized in earnings rather than within stockholders’ equity. If management's estimation process determines that there is no significant value beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest is recognized in earnings. However, if it is determined that significant value likely exists beyond the in-substance real estate, the gain (loss) on the sale of the noncontrolling interest would be recognized within stockholders’ equity. In-substance real estate is comprised of land plus improvements and integral equipment. The determination of whether property, plant and equipment is integral equipment is based on the significance of the costs to remove the equipment from its existing location (including the cost of repairing damage resulting from the removal), combined with the decrease in the fair value of the equipment as a result of those removal activities. When the combined total of removal costs and the decrease in fair value of the equipment exceeds 10% of the fair value of the equipment, the equipment is considered integral equipment. The accounting standards specifically identify power plants as an example of in-substance real estate. Where the consolidated entity in which noncontrolling interests have been sold contains in-substance real estate, management estimates the extent to which the total fair value of the assets of the entity is represented by the in-substance real estate and whether significant value exists beyond the in-substance real estate. This estimation considers all qualitative and quantitative factors relevant for each sale and, where appropriate, includes making quantitative estimates about the fair value of the entity and its identifiable assets and liabilities (including any favorable or unfavorable contracts) by analogy to the accounting standards on business combinations. As such, these estimates may require significant judgment and assumptions, similar to the critical accounting estimates previously disclosed in our 2013 Form 10-K for impairments and fair value.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview Regarding Market Risks
Our generation and utility businesses are exposed to and proactively manage market risk. Our primary market risk exposure is to the price of commodities, particularly electricity, oil, natural gas, coal and environmental credits. We operate in multiple countries and as such are subject to volatility in exchange rates at varying degrees at the subsidiary level and between

53



our functional currency, the U.S. Dollar, and currencies of the countries in which we operate. We are also exposed to interest rate fluctuations due to our issuance of debt and related financial instruments.
These disclosures set forth in this Item 3 are based upon a number of assumptions; actual effects may differ. The safe harbor provided in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 shall apply to the disclosures contained in this Item 3. For further information regarding market risk, see Item 1A. — Risk Factors, Our financial position and results of operations may fluctuate significantly due to fluctuations in currency exchange rates experienced at our foreign operations, Our businesses may incur substantial costs and liabilities and be exposed to price volatility as a result of risks associated with the wholesale electricity markets, which could have a material adverse effect on our financial performance, and We may not be adequately hedged against our exposure to changes in commodity prices or interest rates of the 2013 Form 10-K.
Commodity Price Risk
Although we prefer to hedge our exposure to the impact of market fluctuations in the price of electricity, fuels and environmental credits, some of our generation businesses operate under short-term sales or under contract sales that leave an

56



un-hedged exposure on some of our capacity or through imperfect fuel pass-throughs. In our utility businesses, we may be exposed to commodity price movements depending on our excess or shortfall of generation relative to load obligations and sharing or pass-through mechanisms. These businesses subject our operational results to the volatility of prices for electricity, fuels and environmental credits in competitive markets. We employ risk management strategies to hedge our financial performance against the effects of fluctuations in energy commodity prices. The implementation of these strategies can involve the use of physical and financial commodity contracts, futures, swaps and options.
When hedging the output of our generation assets, we utilize contract strategies that lock in the spread per MWh between variable costs and the price at which the electricity can be sold. The portion of our sales and purchases that are not subject to such agreements or contracted businesses where indexation is not perfectly matched to business drivers will be exposed to commodity price risk.
AES businesses will see changes in variable margin performance as global commodity prices shift. For the remainder of 2014, we project pretax earnings exposure on a 10% move in commodity prices would be approximately $5 million for natural gas, $5 million for oil and less than $5 million for coal. Our estimates exclude correlation of oil with coal or natural gas. For example, a decline in oil or natural gas prices can be accompanied by a decline in coal price if commodity prices are correlated. In aggregate, the Company’s downside exposure occurs with lower oil, lower natural gas, and higher coal prices. Exposures at individual businesses will change as new contracts or financial hedges are executed, and our sensitivity to changes in commodity prices generally increases in later years with reduced hedge levels at some of our businesses.
Commodity prices affect our businesses differently depending on the local market characteristics and risk management strategies. Spot power prices, contract indexation provisions and generation costs can be directly or indirectly affected by movements in the price of natural gas, oil and coal. We have some natural offsets across our businesses such that low commodity prices may benefit certain businesses and be a cost to others. OffsetsExposures are not perfectly linear or symmetric. The sensitivities are affected by a number of local or indirect market factors. Examples of these factors include hydrology, local energy market supply/demand balances, regional fuel supply issues, regional competition, bidding strategies and regulatory interventions such as price caps. Operational flexibility changes the shape of our sensitivities. For instance, certain power plants may limit downside exposure by reducing dispatch in low market environments. Volume variation also affects our commodity exposure. The volume sold under contracts or retail concessions can vary based on weather and economic conditions resulting in a higher or lower volume of sales in spot markets. Thermal unit availability and hydrology can affect the generation output available for sale and can affect the marginal unit setting power prices.
In the US SBU, the generation businesses are largely contracted but may have residual risk to the extent contracts are not perfectly indexed to the business drivers. IPL sells power at wholesale once retail demand is served, so retail sales demand may affect commodity exposure. Additionally, at DPL, open access allows our retail customers to switch to alternative suppliers; falling energy prices may increase the rate at which our customers switch to alternative suppliers; DPL sells generation in excess of its retail demand under short-term sales. Given that natural gas-fired generators set power prices for many markets, higher natural gas prices expand margins. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during some periods.
In the Andes SBU, our business in Chile owns assets in the central and northern regions of the country and has a portfolio of contract sales in both. In the central region, the contract sales generally cover the efficient generation from our coal-fired and hydroelectric assets. Any residual spot price risk will primarily be driven by the amount of hydrological inflows. In the case of low hydroelectric generation, spot price exposure is capped by the ability to dispatch our natural gas/diesel assets.assets which can be an expensive cap depending on fuel pricing at the time required. There is a small amount of coal generation in the northern region that is not covered by the portfolio of contract sales and therefore subject to spot price risk. In both regions, generators with oil or oil-linked fuel generally set power prices. In Colombia, we

54



operate under a short-term sales strategy and have commodity exposure to un-hedged volumes. Because we own hydroelectric assets there, contracts are not indexed to fuel.
In the Brazil SBU, the hydroelectric generating facility is covered by contract sales. Under normal hydrological volatility, spot price risk is mitigated through a regulated sharing mechanism across all hydroelectric generators in the country. Under drier conditions, the sharing mechanism may not be sufficient to cover the business' contract position, and therefore it may have to purchase power at spot prices driven by the cost of thermal generation.
In the MCAC SBU, our businesses have commodity exposure on un-hedged volumes. Panama is largelyhighly contracted under a portfolio of fixed volume contract sales. To the extent hydrological inflows are greater than or less than the contract sales volume, the business will be sensitive to changes in spot power prices which may be driven by oil prices in some time periods. In the Dominican Republic, we own natural gas-fired assets contracted under a portfolio of contract sales and a coal-fired asset contracted with a single contract, and both contract and spot prices may move with commodity prices. Additionally, the contract levels do not always match our generation availability and our assets may be sellers of spot prices in excess of contract levels or a net buyer in the spot market to satisfy contract obligations.

57



In the EMEA SBU, our Kilroot facility operates on a short-term sales strategy. To the extent that sales are un-hedged, the commodity risk at our Kilroot business is to the clean dark spread — the difference between electricity price and our coal-based variable dispatch cost including emissions. Natural gas-fired generators set power prices for many periods, so higher natural gas prices generally expand margins and higher coal or emissions prices reduce them. The positive impact on margins will be moderated if natural gas-fired generators set the market price only during certain peak periods. At our Ballylumford facility, the regulator has the right to terminate the contract, which would impact our commodity exposure. Our operations in Turkey are sensitive to the spread between power and natural gas prices, both of which have historically demonstrated a relationship to oil. As a result of these relationships, falling oil prices could compress margins realized at the business.
In the Asia SBU, our Masinloc business is a coal-fired generation facility which hedges its output under a portfolio of contract sales that are indexed to fuel prices, with generation in excess of contract volume soldor shortfalls of generation relative to contract volumes settled in the spot market. Low oil prices may be a driver of margin compression since oil affects spot power sale prices.
Foreign Exchange Rate Risk
In the normal course of business, we are exposed to foreign currency risk and other foreign operations risks that arise from investments in foreign subsidiaries and affiliates. A key component of these risks stems from the fact that some of our foreign subsidiaries and affiliates utilize currencies other than our consolidated reporting currency, the U.S. Dollar. Additionally, certain of our foreign subsidiaries and affiliates have entered into monetary obligations in the U.S. Dollar or currencies other than their own functional currencies. We have varying degrees of exposure to changes in the exchange rate between the U.S. Dollar and the following currencies: Argentine Peso, Brazilian Real, British Pound, Chilean Peso, Colombian Peso, Dominican Peso, Euro, Indian Rupee, KazakhstaniKazakhstan Tenge, Mexican Peso and Philippine Peso. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. We also use foreign currency forwards, swaps and options, where possible, to manage our risk related to certain foreign currency fluctuations.
We have entered into hedges to partially mitigate the exposure of earnings translated into the U.S. Dollar to foreign exchange volatility. The largest foreign exchange risks over a twelve-month forward-looking period are stemming from the following currencies: Argentine Peso, British Pound, Brazilian Real, Colombian Peso, Euro and Kazakhstan Tenge. As of JuneSeptember 30, 2014, assuming a 10% U.S. Dollar appreciation, adjusted pretax earnings attributable to foreign subsidiaries exposed to movement in the exchange rate of the Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro and Kazakhstan Tenge relative to the U.S. Dollar are projected to be reduced by approximately $5 million, $5 million, $5 million, $5 million, less than $5 million and $5 million respectively,for each currency for the remainder of 2014. These numbers have been produced by applying a one-time 10% U.S. Dollar appreciation to forecasted exposed pretax earnings for 2014 coming from the respective subsidiaries exposed to the currencies listed above, net of the impact of outstanding hedges and holding all other variables constant. The numbers presented above are net of any transactional gains/losses. These sensitivities may change in the future as new hedges are executed or existing hedges are unwound. Additionally, updates to the forecasted pretax earnings exposed to foreign exchange risk may result in further modification. The sensitivities presented do not capture the impacts of any administrative market restrictions or currency inconvertibility.
Interest Rate Risks
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt, as well as interest rate swap, cap and floor and option agreements.
Decisions on the fixed-floating debt ratio are made to be consistent with the risk factors faced by individual businesses or plants. Depending on whether a plant’s capacity payments or revenue stream is fixed or varies with inflation, we partially hedge against interest rate fluctuations by arranging fixed-rate or variable-rate financing. In certain cases, particularly for non-

55



recoursenon-recourse financing, we execute interest rate swap, cap and floor agreements to effectively fix or limit the interest rate exposure on the underlying financing. Most of our interest rate risk is related to non-recourse financings at our businesses.
As of JuneSeptember 30, 2014, the portfolio’s pretax earnings exposure for the remainder of 2014 to a 100-basis-point increase in interest rates for our Argentine Peso, Brazilian Real, British Pound, Colombian Peso, Euro, Kazakhstani Tenge and U.S. Dollar denominated debt would be approximately $10 million based on the impact of a one time, 100-basis-point upward shift in interest rates on interest expense for the debt denominated in these currencies. The amounts do not take into account the historical correlation between these interest rates.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company, under the supervision and with the participation of its management, including the Company’s Chief Executive Officer (“CEO”)CEO and Chief Financial Officer (“CFO”), evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our CEO and CFO have concluded that our

58



disclosure controls and procedures were effective as of JuneSeptember 30, 2014 to ensure that information required to be disclosed by the Company in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Controls over Financial Reporting
ThereOn May 14, 2013, The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control - Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. We have reviewed the 2013 Framework and integrated the changes into the Company’s internal controls over financial reporting. We expect that management’s assessment of the overall effectiveness of our internal controls over financial reporting for the year ending December 31,2014 will be based on the 2013 Framework and that the change will not be significant to our overall control structure over financial reporting.
As of September 30 2014, there were no changes that occurred during the fiscal quarter covered by this Quarterly Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II: OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is involved in certain claims, suits and legal proceedings in the normal course of business. The Company has accrued for litigation and claims where it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company believes, based upon information it currently possesses and taking into account established reserves for estimated liabilities and its insurance coverage, that the ultimate outcome of these proceedings and actions is unlikely to have a material adverse effect on the Company’s financial statements. It is reasonably possible, however, that some matters could be decided unfavorably to the Company and could require the Company to pay damages or make expenditures in amounts that could be material but cannot be estimated as of JuneSeptember 30, 2014.
In 1989, Centrais Elétricas Brasileiras S.A. (“Eletrobrás”) filed suit in the Fifth District Court in the State of Rio de Janeiro (“FDC”) against Eletropaulo Eletricidade de São Paulo S.A. (“EEDSP”) relating to the methodology for calculating monetary adjustments under the parties’ financing agreement. In April 1999, the FDC found for Eletrobrás and in September 2001, Eletrobrás initiated an execution suit in the FDC to collect approximately R$1.511.53 billion ($685629 million) from Eletropaulo (as estimated by Eletropaulo) and a lesser amount from an unrelated company, Companhia de Transmissão de Energia Elétrica Paulista (“CTEEP”) (Eletropaulo and CTEEP were spun off of EEDSP pursuant to its privatization in 1998). In November 2002, the FDC rejected Eletropaulo’s defenses in the execution suit. On appeal, the case was remanded to the FDC for further proceedings.proceedings to determine whether Eletropaulo is liable for the debt. In December 2012, the FDC issued a decision that Eletropaulo is liable for the debt. However, that decision was annulled on appeal and the case was remanded to the FDC for further proceedings. On remand at the FDC, the FDC has appointed an accounting expert who will issue a report on the amount of the alleged debt and the responsibility for its payment in light of the privatization. The parties will be entitled to take discovery and present arguments on the issues to be determined by the expert. The expert has been nominated by the FDC. If the FDC again finds Eletropaulo liable for the debt, after the amount of the alleged debt is determined, Eletrobrás will be entitled to resume the execution suit in the FDC. If Eletrobrás does so, Eletropaulo will be required to provide security for its alleged liability. In that case, if Eletrobrás requests the seizure of such security and the FDC grants such request, Eletropaulo’s results of operations may be materially adversely affected and, in turn, the Company’s results of operations could be materially adversely affected. In addition, in February 2008, CTEEP filed a lawsuit in the FDC against Eletrobrás and Eletropaulo seeking a declaration that CTEEP is not liable for any debt under the financing agreement. Eletropaulo believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In September 1996, a public civil action was asserted against Eletropaulo and Associação Desportiva Cultural Eletropaulo (the “Associação”) relating to alleged environmental damage caused by construction of the Associação near Guarapiranga Reservoir. The initial decision that was upheld by the Appellate Court of the State of São Paulo in 2006 found that Eletropaulo should repair the alleged environmental damage by demolishing certain construction and reforesting the area, and either sponsor an environmental project which would cost approximately R$1.51.6 million ($680656 thousand) as of JuneSeptember 30, 2014, or pay an indemnification amount of approximately R$15 million ($76 million). Eletropaulo has appealed this decision to the Supreme Court and the Supreme Court affirmed the decision of the Appellate Court. Following the Supreme Court’s decision, the case has been remanded to the court of first instance for further proceedings and to monitor compliance by the defendants with the terms of the decision. In January 2014, Eletropaulo informed the court that it intended to comply with the court’s decision by donating a green area inside a protection zone and restore watersheds, the aggregate cost of which is expected to be approximately R$1.51.6 million ($680656 thousand). Eletropaulo also requested that the court add the current owner of the land where the Associação facilities are located, Empresa Metropolitana de Águas e Energia S.A. (“EMAE”), as a party to the lawsuit and order EMAE to perform the demolition and reforestation aspects of the court’s decision. In July 2014, the court requested the Secretary of the Environment for the State of São Paulo to notify the court of its opinion regarding the acceptability of the green areas to be donated by Eletropaulo to the State of São Paulo.
In December 2001, Gridco Ltd. ("Gridco") served a notice to arbitrate pursuant to the Indian Arbitration and Conciliation Act of 1996 on the Company, AES Orissa Distribution Private Limited (“AES ODPL”), and Jyoti Structures (“Jyoti”) pursuant to the terms of the shareholders agreement between Gridco, the Company, AES ODPL, Jyoti and the Central Electricity Supply Company of Orissa Ltd. ("CESCO"), an affiliate of the Company. In the arbitration, Gridco asserted that a comfort letter issued by the Company in connection with the Company's indirect investment in CESCO obligates the Company to provide additional financial support to cover all of CESCO's financial obligations to Gridco. Gridco appeared to be seeking approximately $189 million in damages, plus undisclosed penalties and interest, but a detailed alleged damage analysis was not filed by Gridco. The Company counterclaimed against Gridco for damages. In June 2007, a 2-to-1 majority of the arbitral tribunal rendered its award rejecting Gridco’s claims and holding that none of the respondents, the Company, AES ODPL, or Jyoti, had any liability to Gridco. The respondents’ counterclaims were also rejected. A majority of the tribunal later awarded the respondents, including the Company, some of their costs relating to the arbitration. Gridco filed challenges of the tribunal's awards with the local Indian court. Gridco's challenge of the costs award has been dismissed by the court, but its challenge of the liability award

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remains pending. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.

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In March 2003, the office of the Federal Public Prosecutor for the State of São Paulo, Brazil (“MPF”) notified Eletropaulo that it had commenced an inquiry into the BNDES financings provided to AES Elpa and AES Transgás, the rationing loan provided to Eletropaulo, changes in the control of Eletropaulo, sales of assets by Eletropaulo, and the quality of service provided by Eletropaulo to its customers. The MPF requested various documents from Eletropaulo relating to these matters. In July 2004, the MPF filed a public civil lawsuit in the Federal Court of São Paulo (“FCSP”) alleging that BNDES violated Law 8429/92 (the Administrative Misconduct Act) and BNDES’s internal rules by: (1) approving the AES Elpa and AES Transgás loans; (2) extending the payment terms on the AES Elpa and AES Transgás loans; (3) authorizing the sale of Eletropaulo’s preferred shares at a stock-market auction; (4) accepting Eletropaulo’s preferred shares to secure the loan provided to Eletropaulo; and (5) allowing the restructurings of Light Serviços de Eletricidade S.A. and Eletropaulo. The MPF also named AES Elpa and AES Transgás as defendants in the lawsuit because they allegedly benefited from BNDES’s alleged violations. In May 2006, the FCSP ruled that the MPF could pursue its claims based on the first, second, and fourth alleged violations noted above. The MPF subsequently filed an interlocutory appeal with the Federal Court of Appeals (“FCA”) seeking to require the FCSP to consider all five alleged violations. The lawsuit remains before the FCSP, but the FCSP has suspended the lawsuit pending a decision on MPF's interlocutory appeal. AES Elpa and AES Brasiliana (the successor of AES Transgás) believe they have meritorious defenses to the allegations asserted against them and will defend themselves vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
Pursuant to their environmental audit, AES Sul and AES Florestal discovered 200 barrels of solid creosote waste and other contaminants at a pole factory that AES Florestal had been operating. The conclusion of the audit was that a prior operator of the pole factory, Companhia Estadual de Energia (“CEEE”), had been using those contaminants to treat the poles that were manufactured at the factory. On their initiative, AES Sul and AES Florestal communicated with Brazilian authorities and CEEE about the adoption of containment and remediation measures. In March 2008, the State Attorney of the State of Rio Grande do Sul, Brazil filed a public civil action against AES Sul, AES Florestal and CEEE seeking an order requiring the companies to recover the contaminated area located on the grounds of the pole factory and an indemnity payment (approximately R$6 million ($32 million)) to the State’s Environmental Fund. In October 2011, the State Attorney Office filed a request for an injunction ordering the defendant companies to remediatecontain and remove the contaminated areacontamination immediately. The court granted injunctive relief on October 18, 2011, but determined only that defendant CEEE was required to proceed with the remediationremoval work. In May 2012, CEEE began the remediationremoval work in compliance with the injunction. The remediationremoval costs are estimated to be approximately R$60 million ($2725 million) and the work is ongoing.was completed in February 2014. In parallel with the removal activities, a court-appointed expert investigation took place, which was concluded in May 2014. The parties have until November 2014 to present their response to the report of the court-appointed expert. The case is in the evidentiary stage awaiting the production of the court’s expert opinion on several matters, including which of the parties had utilized the products found in the area. The Company believes that it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2004, the Company received notice of a “Formulation of Charges” filed against the Company by the Superintendence of Electricity of the Dominican Republic. In the “Formulation of Charges,” the Superintendence asserts that the existence of three generation companies (Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”), Dominican Power Partners, and AES Andres BV) and one distribution company (Empresa Distribuidora de Electricidad del Este, S.A. (“Este”)) in the Dominican Republic, violates certain cross-ownership restrictions contained in the General Electricity Law of the Dominican Republic. In February 2004, the Company filed in the First Instance Court of the National District of the Dominican Republic an action seeking injunctive relief based on several constitutional due process violations contained in the “Formulation of Charges” (“Constitutional Injunction”). In February 2004, the Court granted the Constitutional Injunction and ordered the immediate cessation of any effects of the “Formulation of Charges,” and the enactment by the Superintendence of Electricity of a special procedure to prosecute alleged antitrust complaints under the General Electricity Law. In March 2004, the Superintendence of Electricity appealed the Court’s decision. In July 2004, the Company divested any interest in Este. The Superintendence of Electricity’s appeal remains pending. The Company believes it has meritorious defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In March 2009, AES Uruguaiana Empreendimentos S.A. (“AESU”) in Brazil initiated arbitration in the International Chamber of Commerce (“ICC”) against YPF S.A. (“YPF”) seeking damages and other relief relating to YPF’s breach of the parties’ gas supply agreement (“GSA”). Thereafter, in April 2009, YPF initiated arbitration in the ICC against AESU and two unrelated parties, Companhia de Gas do Estado do Rio Grande do Sul and Transportador de Gas del Mercosur S.A. (“TGM”), claiming that AESU wrongfully terminated the GSA and caused the termination of a transportation agreement (“TA”) between YPF and TGM (“YPF Arbitration”). YPF sought an unspecified amount of damages from AESU, a declaration that YPF’s performance was excused under the GSA due to certain alleged force majeure events, or, in the alternative, a declaration that the GSA and the TA should be terminated without a finding of liability against YPF because of the allegedly onerous

61



obligations imposed on YPF by those agreements. In addition, in the YPF Arbitration, TGM asserted that if it was determined that AESU was responsible for the termination of the GSA, AESU was liable for TGM’s alleged losses, including losses under the TA. In April 2011, the arbitrations were consolidated into a single proceeding. The hearing on liability issues took place in December 2011. In May 2013, the arbitral Tribunal issued a liability award in AESU's favor. YPF thereafter challenged the

58



award in Argentine court. In June 2014, at AESU's request, a Uruguayan court temporarily enjoined YPF from pursuing its action in the Argentine court, pending a final determination by the Uruguayan court on whether YPF is entitled to challenge the liability award in the Argentine court. It is unclear whether YPF will complyhas not complied with the temporary injunction.injunction to date. In August 2014, a Uruguayan appellate court issued a decision declaring that only the Uruguayan courts have jurisdiction to review awards in the arbitration and that the Tribunal must disregard litigation outside of Uruguay when deciding issues in the arbitration. In October 2014, an Argentine appellate court issued a decision purporting to suspend the arbitration, and later issued an order threatening sanctions against violations of its decision. Given the competing decisions of the Uruguayan and Argentine courts, the Tribunal has suspended the damages phase of the arbitration until February 2, 2015, at which time the Tribunal will consider whether to lift the suspension. In the arbitration,meantime, the Tribunal has asked the parties are submitting their respective evidence on damages. The final evidentiary hearing on damages will take place on November 6-7, 2014.to remove any alleged obstacles to the progress of the arbitration. AESU believes it has meritorious claims and defenses and will assert them vigorously; however, there can be no assurances that it will be successful in its efforts.

In April 2009, the Antimonopoly Agency in Kazakhstan initiated an investigation of certain power sales of Ust-Kamenogorsk HPP (“UK HPP”) and Shulbinsk HPP, hydroelectric plants under AES concession (collectively, the “Hydros”). The Antimonopoly Agency determined that the Hydros had abused their market position and charged monopolistically high prices for power from January-February 2009. The Agency sought an order from the administrative court requiring UK HPP to pay an administrative fine of approximately KZT 120 million ($1 million)648 thousand) and to disgorge profits for the period at issue, estimated by the Antimonopoly Agency to be approximately KZT 440 million ($2 million). No fines or damages have been paid to date, however, as the proceedings in the administrative court have been suspended due to the initiation of related criminal proceedings against officials of the Hydros. In the course of criminal proceedings, the financial police expanded the periods at issue to the entirety of 2009 for UK HPP and from January-October 2009 for Shulbinsk HPP, and sought increased damages of KZT 1.2 billion ($76 million) from UK HPP and KZT 1.3 billion ($7 million) from Shulbinsk HPP. The Hydros believe they have meritorious defenses and will assert them vigorously in these proceedings; however, there can be no assurances that they will be successful in their efforts.
In October 2009, AES Mérida III, S. de R.L. de C.V. (AES Mérida), one of our businesses in Mexico, initiated arbitration against its fuel supplier and electricity offtaker, Comisión Federal de Electricidad (“CFE”), seeking a declaration that CFE breached the parties’ power purchase agreement (“PPA”) by supplying gas that did not comply with the PPA’s specifications. Alternatively, AES Mérida requested a declaration that the supply of such gas by CFE is a force majeure event under the PPA. CFE disputed the claims. Although it did not assert counterclaims, in its closing brief CFE asserted that it is entitled to a partial refund of the capacity charge payments that it made for power generated with the out-of-specification gas. In July 2012, the arbitral Tribunal issued an award in AES Mérida’s favor. In December 2012, CFE initiated an action in Mexican court seeking to nullify the award. AES Mérida opposed the request and asserted a counterclaim to confirm the award. In February 2014, the court rejected CFE's claims and granted AES Mérida's request to confirm the award. CFE has appealed the court's decision. AES Mérida believes it has meritorious grounds to defeat that action; however, there can be no assurances that it will be successful.
In October 2009, IPL received a Notice of Violation (“NOV”) and Finding of Violation from the EPA pursuant to the Clean Air Act (“CAA”) Section 113(a). The NOV alleges violations of the CAA at IPL’s three primarily coal-fired electric generating facilities dating back to 1986. The alleged violations primarily pertain to the Prevention of Significant Deterioration and nonattainment New Source Review requirements under the CAA. Since receiving the letter, IPL management has met with EPA staff regarding possible resolutions of the NOV. At this time, we cannot predict the ultimate resolution of this matter. However, settlements and litigated outcomes of similar cases have required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects. A similar outcome in this case could have a material impact to IPL and could, in turn, have a material impact on the Company. IPL would seek recovery of any operating or capital expenditures related to air pollution control technology to reduce regulated air emissions; however, there can be no assurances that it would be successful in that regard.
In November 2009, April 2010, December 2010, April 2011, June 2011, August 2011, and November 2011, and October 2014, substantially similar personal injury lawsuits were filed by a total of 4950 residents and decedent estates in the Dominican Republic against the Company, AES Atlantis, Inc., AES Puerto Rico, LP, AES Puerto Rico, Inc., and AES Puerto Rico Services, Inc., in the Superior Court for the State of Delaware. In each lawsuit, the plaintiffs allege that the coal combustion byproductsby-products of AES Puerto Rico’s power plant were illegally placed in the Dominican Republic from October 2003 through March 2004 and subsequently caused the plaintiffs’ birth defects, other personal injuries, and/or deaths. The plaintiffs did not quantify their alleged damages, but generally alleged that they are entitled to compensatory and punitive damages. The Company is not able to estimate damages, if any, at this time. The AES defendants moved for partial dismissal of both the November 2009 and April

62



2010 lawsuits on various grounds. In July 2011, the Superior Court dismissed the plaintiffs’ international law and punitive damages claims, but held that the plaintiffs had stated intentional tort, negligence, and strict liability claims under Dominican law, which the Superior Court found governed the lawsuits. The Superior Court granted the plaintiffs leave to amend their complaints in accordance with its decision, and in September 2011, the plaintiffs in the November 2009 and April 2010 lawsuits did so. In November 2011, the AES defendants again moved for partial dismissal of those amended complaints, and in both lawsuits, the Superior Court dismissed the plaintiffs' claims for future medical monitoring expenses but declined to dismiss their claims under Dominican Republic Law 64-00. The AES defendants filed an answer to the November 2009 lawsuit in June 2012. The Superior Court has stayed the remaining six lawsuits as well as any subsequently filed similar lawsuits. The Superior Court hasbetween April 2010 and November 2011, and may also ordered that, forstay the present,October 2014 lawsuit. Presently, discovery will proceedis proceeding only in the November 2009 lawsuit and will be limited toon causation

59



and exposure issues. The AES defendants believe they have meritorious defenses and will defend themselves vigorously; however, there can be no assurances that they will be successful in their efforts.
On December 21, 2010, AES-3C Maritza East 1 EOOD, which owns a 670 MW lignite-fired power plant in Bulgaria, made the first in a series of demands on the performance bond securing the construction Contractor’s obligations under the parties’ EPC Contract. The Contractor failed to complete the plant on schedule. The total amount demanded by Maritza under the performance bond was approximately €155 million. The Contractor obtained an injunction from a lower French court purportedly preventing the issuing bank from honoring the bond demands. However, the Versailles Court of Appeal canceled the injunction in July 2011, and therefore the issuing bank paid the bond demands in full. In addition, in December 2010, the Contractor stopped commissioning of the power plant’s two units, allegedly because of the purported characteristics of the lignite supplied to it for commissioning. In January 2011, the Contractor initiated arbitration on its lignite claim, seeking an extension of time to complete the power plant, an increase to the contract price, and other relief, including in relation to the bond demands. The Contractor later added claims relating to the alleged unavailability of the grid during commissioning. Maritza rejected the Contractor’s claims and asserted counterclaims for delay liquidated damages and other relief relating to the Contractor’s failure to complete the power plant and other breaches of the EPC Contract. Maritza also terminated the EPC Contract for cause and asserted arbitration claims against the Contractor relating to the termination. The Contractor asserted counterclaims relating to the termination. The Contractor is seeking approximately €240 million ($327304 million) in the arbitration, plus interest and costs. The evidentiary hearing took place on November 27-December 6, 2013, and January 6-17, 2014. Closing arguments were heard on May 21-22, 2014. The parties are awaiting the Tribunal's award. Maritza believes it has meritorious claims and defenses and will assert them vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
On February 11, 2011, Eletropaulo received a notice of violation from São Paulo State’s Environmental Authorities for allegedly destroying 0.32119 hectares of native vegetation at the Conservation Park of Serra do Mar (“Park”), without previous authorization or license. The notice of violation asserted a fine of approximately R$1 million ($454410 thousand) and the suspension of Eletropaulo activities in the Park. As a response to this administrative procedure before the São Paulo State Environmental Authorities (“São Paulo EA”), Eletropaulo timely presented its defense on February 28, 2011 seeking to vacate the notice of violation or reduce the fine. In December 2011, the São Paulo EA declined to vacate the notice of violation but recognized the possibility of 40% reduction inof the fine if Eletropaulo agrees to recover the affected area with additional vegetation. Eletropaulo has not appealed the decision and is now discussing the terms of a possible settlement with the São Paulo EA, including a plan to recover the affected area by primarily planting additional trees. In March 2012, the State of São Paulo Prosecutor’s Office of São Bernardo do Campo initiated a Civil Proceeding to review the compliance by Eletropaulo with the terms of any possible settlement. Eletropaulo has had several meetings and field inspections to settle the details of the recovery project. Eletropaulo was informed by the Park Administrator that the area where the recovery project was to be located was no longer available. The Park Administrator subsequently approved a new area for the recovery project. Eletropaulo is currently awaiting the draft of the agreement by the environmental agency, and expects to proceed with the recovery project after reaching agreement with the environmental agency.
In February 2011, a consumer protection group, S.O.S. Consumidores (“SOSC”), filed a lawsuit in the State of São Paulo Federal Court against the Brazilian Regulatory Agency (“ANEEL”), Eletropaulo and all other distribution companies in the State of São Paulo, claiming that the distribution companies had overcharged customers for electricity. SOSC asserted that the distribution companies’ tariffs had been incorrectly calculated by ANEEL, and that the tariffs were required to be corrected from the effective dates of the relevant concession contracts. SOSC asserted that ANEEL erred in May 2010, when the agency corrected the alleged error going forward but declared that the tariff calculations made in the past were correct. Eletropaulo opposed the lawsuit on the ground that it had not wrongfully collected amounts from its customers, as its tariffs had been calculated in accordance with the concession contract with the Federal Government and ANEEL’s rules. Subsequently, the lawsuit was transferred to the Federal Court of Belo Horizonte ("FCBH"), which was presiding over similar lawsuits against other distribution companies and ANEEL. In January 2014, the FCBH dismissed the lawsuit against Eletropaulo and the other distribution companies. Incompanies ("January 2014 Decision"). An appeal was filed in May 2014, SOSC appealedbut that decision.appeal was unsuccessful. The January 2014 Decision has become final and unappealable. SOSC's lawsuit will continue against ANEEL. If SOSC ultimately

63



prevails against the agency, it is possible that SOSC may file a new lawsuit against Eletropaulo seeking refunds. Eletropaulo estimates that its liability to customers could be approximately R$855 million ($388 million). Eletropaulo believes it has meritorious defenses and willwould vigorously defend itself vigorously in this lawsuit; however, there can be no assurances that it will be successful in its efforts.any such lawsuit.
In June 2011, the São Paulo Municipal Tax Authority (the “Municipality”) filed 60 tax assessments in São Paulo administrative court against Eletropaulo, seeking to collect services tax (“ISS”) that allegedly had not been paid on revenues for services rendered by Eletropaulo. Eletropaulo challenged the assessments on the ground that the revenues at issue were not subject to ISS. In October 2013, the First Instance Administrative Court determined that Eletropaulo was liable for ISS, interest, and related penalties totaling approximately R$2.82.86 billion ($1.271.17 billion) as estimated by Eletropaulo. Eletropaulo has appealed to the Second Instance Administrative Court. No tax is due while the appeal is pending. Eletropaulo believes it has

60



meritorious defenses to the assessments and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In January 2012, the Brazil Federal Tax Authority issued an assessment alleging that AES Tietê paid PIS and COFINS taxes from 2007 to 2010 at a lower rate than the tax authority believed was applicable. AES Tietê challenged the assessment on the ground that the tax rate was set in the applicable legislation. In April 2013, the First Instance Administrative Court determined that AES Tietê should have calculated the taxes at the higher rate and that AES Tietê was liable for unpaid taxes, interest and penalties totaling approximately R$844854 million ($383350 million) as estimated by AES Tietê. AES Tietê has filed an appeal to the Second Instance Administrative Court. No tax is due while the appeal is pending. AES Tietê believes it has meritorious defenses to the claim and will defend itself vigorously in these proceedings; however, there can be no assurances that it will be successful in its efforts.
In August 2012, Fondo Patrimonial de las Empresas Reformadas (“FONPER”) (the Dominican instrumentality that holds the Dominican Republic’s shares in Empresa Generadora de Electricidad Itabo, S.A. (“Itabo”)) filed a criminal complaint against certain current and former employees of AES. The criminal proceedings include a related civil component initiated against Coastal Itabo, Ltd. (“Coastal”) (the AES affiliate shareholder of Itabo) and New Caribbean Investment, S.A. (“NCI”) (the AES affiliate that manages Itabo). FONPER asserts claims relating to the alleged mismanagement of Itabo and seeks approximately $270 million in damages. The Dominican District Attorney (“DA”) has admitted the criminal complaint and is investigating the allegations set forth therein. In September 2012, one of the individual defendants responded to the criminal complaint, denying the charges and seeking an immediate dismissal of same. In April 2013, the DA requested that the Dominican Camara de Cuentas ("Camara") perform an audit of the allegations in the criminal complaint. The audit is ongoing and the Camara has not issued its report to date. Further, in August 2012, Coastal and NCI initiated an international arbitration proceeding against FONPER and the Dominican Republic, seeking a declaration that Coastal and NCI have acted both lawfully and in accordance with the relevant contracts with FONPER and the Dominican Republic in relation to the management of Itabo. Coastal and NCI also seek a declaration that the criminal complaint is a breach of the relevant contracts between the parties, including the obligation to arbitrate disputes. Coastal and NCI further seek damages from FONPER and the Dominican Republic resulting from their breach of contract. FONPER and the Dominican Republic have denied the claims and challenged the jurisdiction of the arbitral Tribunal. The Tribunal has not yet established the procedural schedule for the arbitration.arbitration, but has not yet scheduled the final evidentiary hearing. The AES defendants believe they have meritorious claims and defenses, which they will assert vigorously; however, there can be no assuranceassurances that they will be successful in their efforts.
In April 2013, the East Kazakhstan Ecology Department (“ED”) issued an order directing AES Ust-Kamenogorsk CHP ("UK CHP") to pay approximately KZT 720 million ($4.03.9 million) in damages ("April 2013 Order”). The ED claimed that UK CHP was illegally operating without an emissions permit for 27 days in February-March 2013. In June 2013, the ED filed a lawsuit with the Specialized Interregional Economic Court (the “Economic Court”) seeking to require UK CHP to pay the assessed damages. UK CHP thereafter filed a separate lawsuit with the Economic Court challenging the April 2013 Order and the ED's allegations. In that lawsuit, in August 2013, the Economic Court ruled in UK CHP's favor and required the ED to vacate the April 2013 Order. That ruling was upheld on two intermediate appeals; however,appeals and thereafter the ED maydid not further appeal to the Kazakhstan Supreme Court. The Economic Court also dismissed the lawsuit filed by the ED. UK CHP believes it has meritorious claims and defenses to the claims asserted against it and will defend itself vigorously in these proceedings; however, there can be no assurance that it will be successful in its efforts.
In December 2013, AES Changuinola’s EPC Contractor initiated arbitration pursuant to the parties’ EPC Contract and related settlement agreements. The Contractor alleged, among other things, that AES Changuinola failed to make a settlement payment, release retainage, and acknowledge completion of AES Changuinola hydropower facility. In total, the Contractor sought approximately $41 million in damages, plus interest and costs. AES Changuinola denied the claims and asserted counterclaims against the Contractor. In July 2014, the parties settled the dispute.
ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors as previously disclosed in our 2013 Form 10-K under Part 1 — Item 1A. — Risk Factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table presents information regarding purchases made by The AES Corporation of its common stock:
Repurchase Period Total Number of Shares Purchased Average Price Paid Per Share 
Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1)
 Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan
4/1/2014 - 4/30/14 —
 $—
 —
 $191,479,504
5/1/2014 - 5/31/14 1,165,334
 13.73
 1,165,334
 175,481,733
6/1/2014 - 6/30/14 1,140,379
 13.89
 1,140,379
 159,636,730
Total 2,305,713
 $13.81
 2,305,713
  
Repurchase Period Total Number of Shares Purchased Average Price Paid Per Share 
Total Number of Shares Repurchased as part of a Publicly Announced Purchase Plan (1)
 
Dollar Value of Maximum Number Of Shares To Be Purchased Under the Plan (2)
7/1/2014 - 7/31/14 —
 $—
 —
 $299,636,730
8/1/2014 - 8/31/14 2,594,646
 14.67
 2,594,646
 261,596,648
9/1/2014 - 9/30/14 4,783,741
 14.57
 4,783,741
 191,963,430
Total 7,378,387
 $—
 7,378,387
  
_____________________________

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(1)
(1) See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
(2) The authorization permits the Company to repurchase stock through a variety of methods, including open market repurchases, purchases by contract (including, without limitation, accelerated stock repurchase programs or 10b5-1 plans) and/or privately negotiated transactions. There can be no assurance as to the amount, timing or prices of repurchases, which may vary based on market conditions and other factors. The stock repurchase program may be modified, extended or terminated by the Board of Directors at any time.
See Note 11 — Equity, Stock Repurchase Program to the condensed consolidated financial statements in Item 1. — Financial Statements for further information on our stock repurchase program.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
4.1Eighteenth Supplemental Indenture, dated May 20, 2014, between The AES Corporation and Wells Fargo Bank, N.A. as Trustee is incorporated herein by reference to Exhibit 4.1 of the Company's Form 8-K filed on May 20, 2014.
   
31.1 Rule13a-14(a)/15d-14(a) Certification of Andrés Gluski (filed herewith).
  
31.2 Rule 13a-14(a)/15d-14(a) Certification of Thomas M. O’Flynn (filed herewith).
  
32.1 Section 1350 Certification of Andrés Gluski (filed herewith).
  
32.2 Section 1350 Certification of Thomas M. O’Flynn (filed herewith).
  
101.INS XBRL Instance Document (filed herewith).
  
101.SCH XBRL Taxonomy Extension Schema Document (filed herewith).
  
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith).
  
101.DEF XBRL Taxonomy Extension Definition Linkbase Document (filed herewith).
  
101.LAB XBRL Taxonomy Extension Label Linkbase Document (filed herewith).
  
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith).


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SIGNATURES
Pursuant to the 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.

   
THE AES CORPORATION
(Registrant)
        
Date:August 6,November 5, 2014By: 
/s/ THOMAS M. O’FLYNN
     Name: Thomas M. O’Flynn
     Title: Executive Vice President and Chief Financial Officer (Principal Financial Officer)
        
   By: 
 /s/ SHARON A. VIRAG
     Name: Sharon A. Virag
     Title: Vice President and Controller (Principal Accounting Officer)


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