UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

x	 	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934	
 	 	 	
 	 	For the Quarterly Period Ended: September 30, 2016	
 	 	 	
o	 	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934	
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization)	 	41-1724239
(I.R.S. Employer
Identification No.)	
 	 	 	
804 Carnegie Center, Princeton, New Jersey
(Address of principal executive offices)	 	08540
(Zip Code)	
(609) 524-4500
(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.
Yesx       Noo
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).
Yesx       Noo
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.

Large accelerated filer x	 	Accelerated filer o	 	Non-accelerated filer o	 	Smaller reporting company o	
 	 	 	 	(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).
Yeso       Nox
As of October 31, 2016, there were 315,442,997 shares of common stock outstanding, par value $0.01 per share.

 	

TABLE OF CONTENTS
Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3	
GLOSSARY OF TERMS	5	
PART I — FINANCIAL INFORMATION	10	
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	10	
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	61	
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	107	
ITEM 4 — CONTROLS AND PROCEDURES	109	
PART II — OTHER INFORMATION	110	
ITEM 1 — LEGAL PROCEEDINGS	110	
ITEM 1A — RISK FACTORS	110	
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	110	
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	110	
ITEM 4 — MINE SAFETY DISCLOSURES	110	
ITEM 5 — OTHER INFORMATION	111	
ITEM 6 — EXHIBITS	112	
SIGNATURES	113	

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A —  Risk Factors Related to NRG Energy, Inc. , in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2015, and the following:
 	 	
•	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;	
 	 	
•	Volatile power supply costs and demand for power;	
 	 	
•	Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;	
 	 	
•	The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;	
 	 	
•	Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;	
 	 	
•	NRG's ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;	
 	 	
•	NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;	
 	 	
•	The liquidity and competitiveness of wholesale markets for energy commodities;	
 	 	
•	Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other GHG emissions;	
 	 	
•	Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;	
 	 	
•	NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;	
 	 	
•	NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;	
 	 	
•	NRG's ability to receive loan guarantees or cash grants to support development projects;	
 	 	
•	Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's 2016 Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;	
 	 	
•	GenOn's ability to continue as a going concern;	
 	 	
•	Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide agreed upon coverage;	
 	 	
•	NRG's ability to develop and build new power generation facilities, including new renewable projects;	
 	 	
•	NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;	
 	 	
•	NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;	
 	 	
•	NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;	
 	 	
•	NRG's ability to achieve its strategy of regularly returning capital to stockholders;	
 	 	
•	NRG's ability to obtain and maintain retail market share;	
 	 	
•	NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;	
 	 	
•	NRG's ability to engage in successful mergers and acquisitions activity;	
 	 	
•	NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and	
 	 	
•	NRG's ability to develop and maintain successful partnering relationships.	

3

Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

4

GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

2015 Form 10-K	 	NRG’s Annual Report on Form 10-K for the year ended December 31, 2015	
2016 Revolving Credit Facility	 	The Company’s $2.5 billion revolving credit facility, a component of the 2016 Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021.	
2016 Senior Credit Facility	 	NRG’s senior secured credit facility, comprised of a $1.9 billion term loan facility and a $2.5 billion revolving credit facility, which replaces the Senior Credit Facility.	
2016 Term Loan Facility	 	The Company's $1.9 billion term loan facility due 2023, a component of the 2016 Senior Credit Facility.	
AEP	 	American Electric Power Company Inc.	
ARO	 	Asset Retirement Obligation	
ASC	 	The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP	
ASU	 	Accounting Standards Updates, which reflect updates to the ASC	
Average realized prices	 	Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges	
BACT	 	Best Available Control Technology	
BETM	 	Boston Energy Trading and Marketing LLC	
BTU	 	British Thermal Unit	
Buffalo Bear	 	Buffalo Bear, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Buffalo Bear project	
CAA	 	Clean Air Act	
CAIR	 	Clean Air Interstate Rule	
CAISO	 	California Independent System Operator	
CDD	 	Cooling Degree Day	
CDFW	 	California Department of Fish and Wildlife	
CDWR	 	California Department of Water and Resources	
CenterPoint	 	CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002	
CERT	 	Combustion Emissions Reduction Technologies, LLC	
CFTC	 	U.S. Commodity Futures Trading Commission	
COD	 	Commercial Operation Date	
ComEd	 	Commonwealth Edison	
Company	 	NRG Energy, Inc.	
CPP	 	Clean Power Plan	
CPS	 	Combined Pollutant Standard	
CPUC	 	California Public Utilities Commission	
CSAPR	 	Cross-State Air Pollution Rule	
CVSR	 	California Valley Solar Ranch	
CWA	 	Clean Water Act	
D.C. Circuit	 	U.S. Court of Appeals for the District of Columbia Circuit	
DGPV Holdco 1	 	NRG DGPV Holdco 1 LLC	
DGPV Holdco 2	 	NRG DGPV Holdco 2 LLC	
Discrete Customers	 	Customers measured by unit sales of one-time products or services, such as one-time in-home product installation/maintenance, portable solar products and portable battery solutions	
Distributed Solar	 	Solar power projects that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid	

5

 	
 	 	 	
DSI	 	Dry Sorbent Injection with Trona	
Economic gross margin	 	Sum of energy revenue, capacity revenue and other revenue, less cost of fuels and other cost of sales	
EGU	 	Electric Generating Unit	
El Segundo Energy Center	 	NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project	
EMAAC	 	Eastern Mid-Atlantic Area Council	
EME	 	Edison Mission Energy	
Energy Plus Holdings	 	Energy Plus Holdings LLC and Energy Plus Natural Gas LLC	
EPA	 	U.S. Environmental Protection Agency	
EPC	 	Engineering, Procurement and Construction	
ERCOT	 	Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas	
ESCO	 	Energy Service Company	
ESP	 	Electrostatic Precipitator	
ESPP	 	NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan	
ESPS	 	Existing Source Performance Standards	
Exchange Act	 	The Securities Exchange Act of 1934, as amended	
FASB	 	Financial Accounting Standards Board	
FERC	 	Federal Energy Regulatory Commission	
FirstEnergy	 	FirstEnergy Corp.	
FPA	 	Federal Power Act	
FTRs	 	Financial Transmission Rights	
GAAP	 	Accounting principles generally accepted in the U.S.	
GenConn	 	GenConn Energy LLC	
GenOn	 	GenOn Energy, Inc.	
GenOn Americas Generation	 	GenOn Americas Generation, LLC	
GenOn Americas Generation Senior Notes	 	GenOn Americas Generation's $695 million outstanding unsecured senior notes consisting of $366 million of 8.5% senior notes due 2021 and $329 million of 9.125% senior notes due 2031	
GenOn Mid-Atlantic	 	GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases	
GenOn Senior Notes	 	GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $650 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020	
GHG	 	Greenhouse Gases	
GWh	 	Gigawatt Hour	
HAPs	 	Hazardous Air Pollutants	
HDD	 	Heating Degree Day	
Heat Rate	 	A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh	
HLBV	 	Hypothetical Liquidation at Book Value	
HLM	 	High Lonesome Mesa, LLC	
IASB	 	Independent Accounting Standards Board	
IFRS	 	International Financial Reporting Standards	
IL CPS	 	Illinois Combined Pollutant Standard	
ILU	 	Illinois Union Insurance Company	
ISO	 	Independent System Operator	

6

 	
 	 	 	
ISO-NE	 	ISO New England Inc.	
January 2015 Drop Down Assets	 	The Laredo Ridge, Tapestry and Walnut Creek projects, which were sold to NRG Yield, Inc. on January 2, 2015	
KPPH	 	1,000 Pounds Per Hour	
kWh	 	Kilowatt-hours	
Laredo Ridge	 	Laredo Ridge Wind, LLC, the operating subsidiary of Mission Wind Laredo, LLC, which owns the Laredo Ridge project	
LIBOR	 	London Inter-Bank Offered Rate	
LSE	 	Load Serving Entity	
LTIPs	 	Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan	
MAAC	 	Mid-Atlantic Area Council	
Marsh Landing	 	NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)	
Mass Market	 	Residential and small commercial customers	
MATS	 	Mercury and Air Toxics Standards promulgated by the EPA	
MDE	 	Maryland Department of the Environment	
Midwest Generation	 	Midwest Generation, LLC	
MISO	 	Midcontinent Independent System Operator, Inc.	
MMBtu	 	Million British Thermal Units	
MW	 	Megawatts	
MWG	 	Midwest Generation, LLC	
MWh	 	Saleable megawatt hours, net of internal/parasitic load megawatt-hours	
MWt	 	Megawatts Thermal Equivalent	
NAAQS	 	National Ambient Air Quality Standards	
NEPOOL	 	New England Power Pool	
NERC	 	North American Electric Reliability Corporation	
Net Exposure	 	Counterparty credit exposure to NRG, net of collateral	
Net Generation	 	The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation	
NOL	 	Net Operating Loss	
NOx	 	Nitrogen Oxides	
NPDES	 	National Pollutant Discharge Elimination System	
NPNS	 	Normal Purchase Normal Sale	
NRC	 	U.S. Nuclear Regulatory Commission	
NRG	 	NRG Energy, Inc.	
NRG Wind TE Holdco	 	NRG Wind TE Holdco LLC	
NRG Yield	 	Reporting segment that includes the projects held by NRG Yield, Inc.	
NRG Yield 2019 Convertible Notes	 	$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.	
NRG Yield 2020 Convertible Notes	 	$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.	
NRG Yield, Inc.	 	NRG Yield, Inc., the owner of 53.3% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock	
NRG Yield Operating 2024 Senior Notes	 	NRG Yield Operating LLC's $500 million of 5.375% unsecured senior notes due 2024
	
NRG Yield Operating 2026 Senior Notes	 	NRG Yield Operating LLC's $350 million of 5.00% unsecured senior notes due 2026	
NSR	 	New Source Review	
NSPS	 	New Source Performance Standards	
Nuclear Decommissioning Trust Fund	 	NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2	

7

 	
 	 	 	
NYAG	 	State of New York Office of Attorney General	
NYISO	 	New York Independent System Operator	
NYSERDA	 	New York State Energy Research and Development Authority	
NYSPSC	 	New York State Public Service Commission	
OCI	 	Other Comprehensive Income/(Loss)	
Peaking	 	Units expected to satisfy demand requirements during the periods of greatest or peak load on the system	
PG&E	 	Pacific Gas and Electric Company	
Pinnacle	 	Pinnacle Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Pinnacle project	
PJM	 	PJM Interconnection, LLC	
PM	 	Particulate Matter	
PPA	 	Power Purchase Agreement	
PSD	 	Prevention of Significant Deterioration	
PUCO	 	Public Utility Commission of Ohio	
PUCT	 	Public Utility Commission of Texas	
RAPA	 	Resource Adequacy Purchase Agreement	
RCRA	 	Resource Conservation and Recovery Act of 1976	
REMA	 	NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively	
Reliant Energy	 	Reliant Energy Retail Services, LLC	
Repowering	 	Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, generally to achieve a substantial emissions reduction, increase facility capacity, and improve system efficiency	
RESA	 	Retail Electric Supply Association	
Retail Mass	 	Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG	
Retail Mass Recurring Customers	 	Customers that subscribe to one or more recurring services, such as electricity, natural gas and protection products, the majority of which are retail electricity customers in Texas and the Northeast	
Revolving Credit Facility	 	Prior to June 30, 2016, the Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility, with the 2016 Senior Credit Facility.	
RGGI	 	Regional Greenhouse Gas Initiative	
RMR	 	Reliability Must-Run	
RPV Holdco	 	NRG RPV Holdco 1 LLC	
RTO	 	Regional Transmission Organization	
SCE	 	Southern California Edison	
SDG&E	 	San Diego Gas & Electric Company	
SEC	 	U.S. Securities and Exchange Commission	
Securities Act	 	The Securities Act of 1933, as amended	
Senior Credit Facility	 	Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility with the 2016 Senior Credit Facility.	
Senior Notes	 	As of September 30, 2016, the Company’s $5.8 billion outstanding unsecured senior notes, consisting of $584 million of 7.625% senior notes due 2018, $399 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million of 6.625% senior notes due 2023, $734 million of 6.25% senior notes due 2024, $1.0 billion of 7.25% senior notes due 2026 and $1.25 billion of 6.625% senior notes due 2027.	
Seward	 	The Seward Power Generating Station, a 525 MW coal-fired facility in Pennsylvania	
Shelby	 	The Shelby County Generating Station, a 352 MW natural gas-fired facility in Illinois	

8

 	
 	 	 	
SO2	 	Sulfur Dioxide	
STP	 	South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest	
S&P	 	Standard & Poor's	
Taloga	 	Taloga Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Taloga project	
TCPA	 	Telephone Consumer Protection Act	
Term Loan Facility	 	Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced its Senior Credit Facility, including the Term Loan Facility, with the 2016 Senior Credit Facility.	
TSA	 	Transportation Services Agreement	
TWCC	 	Texas Westmoreland Coal Co.	
UPMC	 	University of Pittsburgh Medical Center	
U.S.	 	United States of America	
U.S. DOE	 	U.S. Department of Energy	
Utility Scale Solar	 	Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level	
VaR	 	Value at Risk	
VIE	 	Variable Interest Entity	
Walnut Creek	 	NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project	

9

PART I — FINANCIAL INFORMATION
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

 	Three months ended September 30,	 	Nine months ended September 30,	
(In millions, except for per share amounts)	2016	 	2015	 	2016	 	2015	
Operating Revenues	 	 	 	 	 	 	 	
Total operating revenues	$	3,952	
 	
 	$	4,434	
 	
 	$	9,819	
 	
 	$	11,663	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	
Cost of operations	2,793	
 	
 	3,042	
 	
 	6,738	
 	
 	8,551	
 	
Depreciation and amortization	357	
 	
 	382	
 	
 	979	
 	
 	1,173	
 	
Impairment losses	8	
 	
 	263	
 	 	123	
 	
 	263	
 	
Selling, general and administrative	282	
 	
 	327	
 	
 	802	
 	
 	878	
 	
Acquisition-related transaction and integration costs	—	
 	
 	3	
 	
 	7	
 	
 	16	
 	
Development activity expenses	23	
 	
 	38	
 	
 	67	
 	
 	109	
 	
Total operating costs and expenses	3,463	
 	 	4,055	
 	 	8,716	
 	 	10,990	
 	
Gain on sale of assets and postretirement benefits curtailment, net	266	
 	
 	—	
 	
 	215	
 	
 	14	
 	
Operating Income	755	
 	 	379	
 	 	1,318	
 	 	687	
 	
Other Income/(Expense)	

 	 	
 	
Equity in earnings of unconsolidated affiliates	16	
 	
 	24	
 	
 	13	
 	
 	29	
 	
Impairment loss on investment	(8	)	
 	—	
 	
 	(147	)	
 	—	
 	
Other income, net	9	
 	
 	4	
 	
 	35	
 	
 	27	
 	
Loss on debt extinguishment, net	(50	)	
 	(2	)	
 	(119	)	
 	(9	)	
Interest expense	(280	)	
 	(291	)	
 	(841	)	
 	(855	)	
Total other expense	(313	)	 	(265	)	 	(1,059	)	 	(808	)	
Income/(Loss) Before Income Taxes	442	
 	
 	114	
 	
 	259	
 	
 	(121	)	
Income tax expense/(benefit)	49	
 	
 	47	
 	
 	95	
 	
 	(43	)	
Net Income/(Loss)	393	
 	
 	67	
 	
 	164	
 	
 	(78	)	
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	(9	)	
 	1	
 	
 	(49	)	
 	(10	)	
Net Income/(Loss) Attributable to NRG Energy, Inc.	402	
 	
 	66	
 	
 	213	
 	
 	(68	)	
Gain on redemption, net of dividends for preferred shares	—	
 	
 	5	
 	
 	(73	)	
 	15	
 	
Income/(Loss) Available for Common Stockholders	$	402	
 	 	$	61	
 	 	$	286	
 	 	$	(83	)	
Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding — basic	316	
 	
 	331	
 	
 	315	
 	
 	334	
 	
Earnings/(Loss) per Weighted Average Common Share — Basic	$	1.27	
 	
 	$	0.18	
 	
 	$	0.91	
 	
 	$	(0.25	)	
Weighted average number of common shares outstanding — diluted	317	
 	
 	332	
 	
 	316	
 	
 	334	
 	
Earnings/(Loss) per Weighted Average Common Share — Diluted	$	1.27	
 	
 	$	0.18	
 	
 	$	0.91	
 	
 	$	(0.25	)	
Dividends Per Common Share	$	0.03	
 	
 	$	0.15	
 	
 	$	0.21	
 	
 	$	0.44	
 	
See accompanying notes to condensed consolidated financial statements.

10

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
(Unaudited)

 	Three months ended September 30,	 	Nine months ended September 30,	
 	2016	 	2015	 	2016	 	2015	
 	(In millions)	
Net Income/(Loss)	$	393	
 	
 	$	67	
 	
 	$	164	
 	
 	$	(78	)	
Other Comprehensive Income/(Loss), net of tax	

 	 	
 	
Unrealized gains/(losses) on derivatives, net of income tax (benefit)/expense of $(1), $(12), $1 and $(6)	27	
 	
 	(6	)	
 	(8	)	
 	(2	)	
Foreign currency translation adjustments, net of income tax benefit of $0 , $5, $0 and $6	3	
 	
 	(8	)	
 	6	
 	
 	(10	)	
Available-for-sale securities, net of income tax expense of $0, $6, $0 and $1	—	
 	
 	(7	)	
 	1	
 	
 	(11	)	
Defined benefit plans, net of tax expense of $0, $2, $0 and $6	31	
 	
 	3	
 	
 	32	
 	
 	9	
 	
Other comprehensive income/(loss)	61	
 	 	(18	)	 	31	
 	 	(14	)	
Comprehensive Income/(Loss)	454	
 	 	49	
 	 	195	
 	 	(92	)	
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests	(2	)	
 	(17	)	
 	(70	)	
 	(34	)	
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	456	
 	 	66	
 	 	265	
 	 	(58	)	
Gain on redemption, net of dividends for preferred shares	—	
 	
 	5	
 	
 	(73	)	
 	15	
 	
Comprehensive Income/(Loss) Available for Common Stockholders	$	456	
 	 	$	61	
 	 	$	338	
 	 	$	(73	)	
See accompanying notes to condensed consolidated financial statements.

11

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

 	 	 	 	 	 	 	 	
 	September 30, 2016	 	December 31, 2015	
(In millions, except shares)	(unaudited)	 	 	
ASSETS	 	 	 	
Current Assets	 	 	 	
Cash and cash equivalents	$	2,435	
 	
 	$	1,518	
 	
Funds deposited by counterparties	16	
 	
 	106	
 	
Restricted cash	480	
 	
 	414	
 	
Accounts receivable, net	1,362	
 	
 	1,157	
 	
Inventory	1,017	
 	
 	1,252	
 	
Derivative instruments	964	
 	
 	1,915	
 	
Cash collateral paid in support of energy risk management activities	337	
 	
 	568	
 	
Renewable energy grant receivable, net	34	
 	
 	13	
 	
Current assets held-for-sale	—	
 	
 	6	
 	
Prepayments and other current assets	369	
 	
 	442	
 	
Total current assets	7,014	
 	
 	7,391	
 	
Property, plant and equipment, net	18,203	
 	
 	18,732	
 	
Other Assets	 	 	 	
Equity investments in affiliates	900	
 	
 	1,045	
 	
Notes receivable, less current portion	21	
 	
 	53	
 	
Goodwill	999	
 	
 	999	
 	
 Intangible assets, net	2,106	
 	
 	2,310	
 	
Nuclear decommissioning trust fund	605	
 	
 	561	
 	
Derivative instruments	256	
 	
 	305	
 	
Deferred income taxes	189	
 	
 	167	
 	
Non-current assets held-for-sale	—	
 	
 	105	
 	
Other non-current assets	1,198	
 	
 	1,214	
 	
Total other assets	6,274	
 	
 	6,759	
 	
Total Assets	$	31,491	
 	
 	$	32,882	
 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	
Current Liabilities	 	 	 	
Current portion of long-term debt and capital leases	$	1,221	
 	
 	$	481	
 	
Accounts payable	945	
 	
 	869	
 	
Derivative instruments	969	
 	
 	1,721	
 	
Cash collateral received in support of energy risk management activities	16	
 	
 	106	
 	
Current liabilities held-for-sale	—	
 	
 	2	
 	
Accrued expenses and other current liabilities	1,150	
 	
 	1,196	
 	
Total current liabilities	4,301	
 	
 	4,375	
 	
Other Liabilities	 	
 	 	
Long-term debt and capital leases	18,018	
 	
 	18,983	
 	
Nuclear decommissioning reserve	284	
 	
 	326	
 	
Nuclear decommissioning trust liability	309	
 	
 	283	
 	
Deferred income taxes	47	
 	
 	19	
 	
Derivative instruments	475	
 	
 	493	
 	
Out-of-market contracts, net	1,065	
 	
 	1,146	
 	
Non-current liabilities held-for-sale	—	
 	
 	4	
 	
Other non-current liabilities	1,480	
 	
 	1,488	
 	
Total non-current liabilities	21,678	
 	
 	22,742	
 	
Total Liabilities	25,979	
 	
 	27,117	
 	
2.822% convertible perpetual preferred stock	—	
 	
 	302	
 	
Redeemable noncontrolling interest in subsidiaries	19	
 	
 	29	
 	
Commitments and Contingencies	

 	

Stockholders’ Equity	

 	
Common stock	4	
 	
 	4	
 	
Additional paid-in capital	8,370	
 	
 	8,296	
 	
Retained deficit	(2,791	)	
 	(3,007	)	
Less treasury stock, at cost — 102,140,814 and 102,749,908 shares, respectively	(2,399	)	
 	(2,413	)	
Accumulated other comprehensive loss	(142	)	
 	(173	)	
Noncontrolling interest	2,451	
 	
 	2,727	
 	
Total Stockholders’ Equity	5,493	
 	
 	5,434	
 	
Total Liabilities and Stockholders’ Equity	$	31,491	
 	
 	$	32,882	

See accompanying notes to condensed consolidated financial statements.

12

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

 	Nine months ended September 30,	
 	2016	 	2015	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	
Net Income/(Loss)	$	164	
 	
 	$	(78	)	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:	

 	
Distributions and equity in earnings of unconsolidated affiliates	44	
 	
 	28	
 	
Depreciation and amortization	979	
 	
 	1,173	
 	
Provision for bad debts	36	
 	
 	49	
 	
Amortization of nuclear fuel	39	
 	
 	36	
 	
Amortization of financing costs and debt discount/premiums	3	
 	
 	(9	)	
Adjustment to loss on debt extinguishment	21	
 	
 	9	
 	
Amortization of intangibles and out-of-market contracts	73	
 	
 	68	
 	
Amortization of unearned equity compensation	23	
 	
 	37	
 	
Impairment losses	270	
 	
 	263	
 	
Changes in deferred income taxes and liability for uncertain tax benefits	29	
 	
 	(72	)	
Changes in nuclear decommissioning trust liability	24	
 	
 	1	
 	
Changes in derivative instruments	82	
 	
 	180	
 	
Changes in collateral deposits supporting energy risk management activities	231	
 	
 	(180	)	
Proceeds from sale of emission allowances	47	
 	
 	(6	)	
Gain on sale of assets and equity method investments, net and postretirement benefits curtailment	(224	)	
 	(14	)	
Cash used by changes in other working capital	(108	)	
 	(93	)	
Net Cash Provided by Operating Activities	1,733	
 	
 	1,392	
 	
Cash Flows from Investing Activities	 	
 	 	
Acquisitions of businesses, net of cash acquired	(18	)	
 	(31	)	
Capital expenditures	(898	)	
 	(889	)	
Increase in restricted cash, net	(30	)	
 	(41	)	
(Increase)/decrease in restricted cash to support equity requirements for U.S. DOE funded projects	(36	)	
 	1	
 	
Decrease in notes receivable	2	
 	
 	10	
 	
Purchases of emission allowances	(32	)	
 	(40	)	
Proceeds from sale of emission allowances	47	
 	
 	45	
 	
Investments in nuclear decommissioning trust fund securities	(378	)	
 	(500	)	
Proceeds from the sale of nuclear decommissioning trust fund securities	354	
 	
 	499	
 	
Proceeds from renewable energy grants and state rebates	11	
 	
 	62	
 	
Proceeds from sale of assets, net of cash disposed of	636	
 	
 	1	
 	
Investments in unconsolidated affiliates	(23	)	
 	(357	)	
Other	44	
 	
 	8	
 	
Net Cash Used by Investing Activities	(321	)	
 	(1,232	)	
Cash Flows from Financing Activities	 	
 	 	
Payment of dividends to common and preferred stockholders	(66	)	
 	(152	)	
Payment for treasury stock	—	
 	
 	(353	)	
Payment for preferred shares	(226	)	
 	—	
 	
Net receipts from settlement of acquired derivatives that include financing elements	129	
 	
 	138	
 	
Proceeds from issuance of long-term debt	5,237	
 	
 	679	
 	
Payments for short and long-term debt	(5,357	)	
 	(954	)	
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	(127	)	
 	651	
 	
Proceeds from issuance of common stock	1	
 	
 	1	
 	
Payment of debt issuance costs	(70	)	
 	(14	)	
Other - contingent consideration	(10	)	
 	(22	)	
Net Cash Used by Financing Activities	(489	)	
 	(26	)	
Effect of exchange rate changes on cash and cash equivalents	(6	)	
 	15	
 	
Net Increase in Cash and Cash Equivalents	917	
 	
 	149	
 	
Cash and Cash Equivalents at Beginning of Period	1,518	
 	
 	2,116	
 	
Cash and Cash Equivalents at End of Period	$	2,435	
 	
 	$	2,265	
 	
See accompanying notes to condensed consolidated financial statements.

13

NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Basis of Presentation
NRG Energy, Inc., or NRG or the Company, is an integrated competitive power company that aims to create a sustainable energy future by producing, selling and delivering energy and energy products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG has one of the nation's largest and most diverse competitive generation portfolios balanced with a leading retail electricity platform. The Company owns and operates approximately 46,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG,” "Reliant" and other retail brand names owned by NRG.
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2015 Form 10-K. Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of September 30, 2016, and the results of operations, comprehensive income/(loss) and cash flows for the three and nine months ended September 30, 2016 and 2015.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.
The Company decreased accumulated depreciation and facilities and equipment within total property, plant and equipment by approximately $1 billion respectively, to adjust amounts previously presented as of December 31, 2015. This adjustment had no impact on net assets at December 31, 2015. Accordingly, the Company does not consider the adjustment to be material to the consolidated balance sheet. Consolidated operating income and net income for the three months and nine months ended September 30, 2016 were not impacted by the adjustment.

14

Note 2 — Summary of Significant Accounting Policies 
Other Balance Sheet Information
The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property plant and equipment, net; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net.

 	September 30, 2016	December 31, 2015	
 	(In millions)	
Accounts receivable allowance for doubtful accounts	$	28	
 	$	26	
 	
Property plant and equipment accumulated depreciation	6,424	
 	5,761	
 	
Intangible assets accumulated amortization	1,729	
 	1,590	
 	
Out-of-market contracts accumulated amortization	740	
 	639	
 	
Other Cash Flow Information
NRG’s investing activities exclude capital expenditures of $112 million which were accrued and unpaid at September 30, 2016.
Noncontrolling Interest
The following table reflects the changes in NRG's noncontrolling interest balance:

 	(In millions)	
Balance as of December 31, 2015	$	2,727	
 	
Distributions to noncontrolling interest	(135	)	
Dividends paid to NRG Yield, Inc. public shareholders	(68	)	
Comprehensive loss attributable to noncontrolling interest	(45	)	
Sale of assets to NRG Yield, Inc.	(37	)	
Redemption of noncontrolling interest	(7	)	
Contributions from noncontrolling interest	16	
 	
Balance as of September 30, 2016	$	2,451	

Redeemable Noncontrolling Interest
The following table reflects the changes in the Company's redeemable noncontrolling interest balance:

 	(In millions)	
Balance as of December 31, 2015	$	29	
 	
Distributions to redeemable noncontrolling interest	(46	)	
Contributions from redeemable noncontrolling interest	61	
 	
Comprehensive loss attributable to redeemable noncontrolling interest	(25	)	
Balance as of September 30, 2016	$	19	
 	
Recent Accounting Developments
ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16.  The amendments of ASU No. 2016-16 were issued to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory.  Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting.  The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and do not require new disclosure requirements.  The amendments of ASU No. 2016-16 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods.  Early adoption is permitted and the adoption of ASU No. 2016-16 should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.  The Company is currently evaluating the impact of the standard on the Company’s results of operations, cash flows and financial position.

15

ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The amendments of ASU No. 2016-15 are effective for public entities for fiscal years beginning after December 15, 2017 and interim periods in those fiscal years. Early adoption is permitted, including adoption in an interim fiscal period with all amendments adopted in the same period. The adoption of ASU No. 2016-15 is required to be applied retrospectively. The Company is currently evaluating the impact of the standard on the Company's statement of cash flows.
ASU 2016-09 — In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU No. 2016-09. The amendments of ASU No. 2016-09 were issued as part of the FASB's Simplification Initiative focused on improving areas of GAAP for which cost and complexity may be reduced while maintaining or improving the usefulness of information disclosed within the financial statements. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The guidance in ASU No. 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.
ASU 2016-07 — In March 2016, the FASB issued ASU No. 2016-07, Investments - Equity Method and Joint Ventures  (Topic 323), or ASU No. 2016-07. The amendments of ASU No. 2016-07 eliminate the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amendments require that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting with no retroactive adjustment to the investment. In addition, ASU No. 2016-07 requires that an entity that has an available-for-sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. The guidance in ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The adoption of ASU No. 2016-07 is required to be applied prospectively and early adoption is permitted. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

16

ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU No. 2016-02. The amendments of ASU No. 2016-02 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common leasing standard for GAAP and International Financial Reporting Standards, or IFRS, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting. The guidance in ASU No. 2016-02 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, ASU No. 2016-02 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The guidance in ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those annual periods. The adoption of ASU No. 2016-02 is required to be applied using a modified retrospective approach for the earliest period presented and early adoption is permitted. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard and evaluating the impact of ASU No. 2016-02 on the Company's results of operations, cash flows and financial position.
ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income.  Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset.  The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.
ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments , or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing either on the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The Company adopted ASU No. 2015-16 for the year ended December 31, 2016, and the adoption did not have a material impact on the Company's results of operations, cash flows and financial position.
ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09. The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. In addition to ASU No. 2014-09, the FASB has issued additional guidance which provides further clarification on Topic 606 including ASU No. 2016-08, ASU No. 2016-10 and ASU No. 2016-12. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a four step process to be applied by an entity in evaluating its contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016. The Company is working through an adoption plan which includes the evaluation of revenue contracts compared to the new standard and evaluating the impact of Topic 606 on the Company's results of operations, cash flows and financial position.

17

Note 3 — Business Acquisitions and Dispositions 
The Company has completed the following business acquisitions and dispositions that are material to the Company's financial statements:
Acquisitions
2015 Acquisition of Desert Sunlight
On June 29, 2015, NRG Yield, Inc., through its subsidiary NRG Yield Operating LLC, acquired 25% of the membership interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285 million. The Company accounts for its 25% investment as an equity method investment.
SunEdison Utility-Scale Solar and Wind Acquisition
On September 15, 2016, the Company entered into an agreement with SunEdison to acquire (i) an equity interest in a tax-equity portfolio of 530 MW mechanically-complete solar assets of which NRG’s net interest based on cash to be distributed will be 265 MW, and an additional 937 MW of solar and wind assets in development, (ii) a 154 MW construction-ready solar facility in Texas and (iii) a 182 MW portfolio of construction-ready and development solar assets in Hawaii.  The acquisition of the portfolio of solar assets in Hawaii was completed on October 7, 2016 for upfront cash consideration of $2 million and the acquisition of the 530 MW tax equity portfolio and 937 MW development assets was completed on November 2, 2016 for upfront cash consideration of $111 million. The Company expects to pay total upfront cash consideration for the three acquisitions of $129 million, with an estimated $59 million in additional payments contingent upon future development milestones.
SunEdison Solar Distributed Generation Acquisition
On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $68 million, subject to post closing adjustments.  The Company expects to sell these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc.
Dispositions
Potrero Disposition
On September 26, 2016, NRG Potrero LLC, or Potrero, an indirect wholly owned subsidiary of GenOn Americas Generation, completed the sale of real property at the Potrero generating station located in San Francisco, CA to California Barrel Company, LLC for total consideration of $86 million, consisting of $74 million of cash received, which is net of $8 million of closing costs and $4 million to be held in escrow in order to cover post closing obligations. This transaction resulted in a gain on sale of $74 million.
Disposition of Majority Interest in EVgo
On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG retained its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and EVgo will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $78 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million, of which $50 million remains as of September 30, 2016. At September 30, 2016, the Company's remaining 35% interest in EVgo of $10 million was accounted for as an equity-method investment.

18

Rockford Disposition
On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets and as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 7,  Impairments .
Aurora Disposition
On May 12, 2016, GenOn entered into an agreement with RA Generation, LLC to sell the Aurora Generating Station, or Aurora, for cash consideration of $365 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Aurora is a 878 MW natural gas facility located in Aurora, Illinois. On July 12, 2016, GenOn completed the sale of Aurora for cash proceeds of $369 million, including $4 million in adjustments for the PJM base residual auction results and estimated working capital, which is subject to further adjustment. The Company recorded a gain of approximately $188 million recognized within the Company's consolidated results of operations during the quarter ended September 30, 2016.
Seward Disposition
On November 24, 2015, GenOn entered into an agreement with Seward Generation, LLC and an affiliate of Robindale Energy Services, Inc. to sell the Seward Generating Station, a 525 MW coal-fired facility in Pennsylvania, for cash consideration of $75 million. At December 31, 2015, GenOn had classified on its balance sheet the assets and liabilities of Seward as held for sale. On February 2, 2016, GenOn completed the sale of Seward and received gross cash proceeds of $75 million, excluding $3 million cash on hand transferred to the buyer. GenOn will also receive $5 million in deferred cash consideration in five $1 million annual installments and up to $2.5 million in payments contingent upon certain environmental requirements being imposed by August 2017. In addition, Robindale committed to future inventory purchases from GenOn of $13 million through 2019.
Shelby Disposition
On November 9, 2015, GenOn entered into an agreement with an affiliate of Rockland Power Partners II, LP to sell the Shelby Generating Station, a 352 MW natural gas-fired facility located in Illinois for cash consideration of $46 million. At December 31, 2015, GenOn had classified on its balance sheet the assets and liabilities of Shelby as held for sale. On March 1, 2016, GenOn completed the sale of Shelby for cash proceeds of $46 million, which resulted in a gain of $29 million recognized during the first quarter of 2016. In addition, GenOn retained $10 million related to future revenue rights retained as part of the agreement of which $7 million had been received as of September 30, 2016.
Transfer of Assets under Common Control
On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million.
On November 3, 2015, the Company sold 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW, to NRG Yield, Inc. NRG Yield, Inc. paid total cash consideration of $209 million, subject to working capital adjustments. NRG Yield, Inc. is responsible for its pro-rata share of non-recourse project debt of $193 million and noncontrolling interest associated with a tax equity structure of $159 million (as of the acquisition date). In February 2016, the Company made a final working capital payment of $2 million to NRG Yield, Inc. reducing total cash consideration to $207 million.

19

Note 4 — Fair Value of Financial Instruments 
This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments , to the Company's 2015 Form 10-K.
For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:

 	As of September 30, 2016	 	As of December 31, 2015	
 	Carrying Amount	 	Fair Value	 	Carrying Amount	 	Fair Value	
 	(In millions)	
Assets:	 	 	 	 	 	 	 	
Notes receivable (a)	$	50	
 	 	$	50	
 	 	$	73	
 	 	$	73	
 	
Liabilities:	 	 	 	 	 	 	 	
Long-term debt, including current portion (b)	19,411	
 	 	18,888	
 	 	19,620	
 	 	18,263	
 	
(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of September 30, 2016 and December 31, 2015:

 	As of September 30, 2016	 	As of December 31, 2015	
 	Level 2	 	Level 3	 	Level 2	 	Level 3	
 	(In millions)	
Long-term debt, including current portion	$	11,767	
 	 	$	7,121	
 	 	$	11,028	
 	 	$	7,235	

20

Recurring Fair Value Measurements
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:

 	As of September 30, 2016	
 	Fair Value	
(In millions)	Level 1	 	Level 2	 	Level 3	 	Total	
Investment in available-for-sale securities (classified within other
    non-current assets):	 	 	 	 	 	 	 	
Debt securities	$	—	
 	 	$	—	
 	 	$	17	
 	 	$	17	
 	
Available-for-sale securities	10	
 	 	—	
 	 	—	
 	 	10	
 	
Other (a)	10	
 	 	—	
 	 	—	
 	 	10	
 	
Nuclear trust fund investments:	 	 	 	 	 	 	 	
Cash and cash equivalents	24	
 	 	—	
 	 	—	
 	 	24	
 	
U.S. government and federal agency obligations	51	
 	 	1	
 	 	—	
 	 	52	
 	
Federal agency mortgage-backed securities	—	
 	 	68	
 	 	—	
 	 	68	
 	
Commercial mortgage-backed securities	—	
 	 	17	
 	 	—	
 	 	17	
 	
Corporate debt securities	—	
 	 	87	
 	 	—	
 	 	87	
 	
Equity securities	301	
 	 	—	
 	 	54	
 	 	355	
 	
Foreign government fixed income securities	—	
 	 	2	
 	 	—	
 	 	2	
 	
Other trust fund investments:	 	 	 	 	 	 	 	
U.S. government and federal agency obligations	1	
 	 	—	
 	 	—	
 	 	1	
 	
Derivative assets:	 	 	 	 	 	 	 	
Commodity contracts	308	
 	 	798	
 	 	107	
 	 	1,213	
 	
Interest rate contracts	—	
 	 	7	
 	 	—	
 	 	7	
 	
Total assets	$	705	
 	 	$	980	
 	 	$	178	
 	 	$	1,863	
 	
Derivative liabilities:	 	 	 	 	 	 	 	
Commodity contracts	375	
 	 	773	
 	 	133	
 	 	1,281	
 	
Interest rate contracts	—	
 	 	163	
 	 	—	
 	 	163	
 	
Total liabilities	$	375	
 	 	$	936	
 	 	$	133	
 	 	$	1,444	
 	
(a) Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for certain former employees.

21

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	As of December 31, 2015	
 	Fair Value	
(In millions)	Level 1	 	Level 2	 	Level 3	 	Total	
Investment in available-for-sale securities (classified within other
non-current assets):	 	 	 	 	 	 	 	
Debt securities	$	—	
 	 	$	—	
 	 	$	17	
 	 	$	17	
 	
Available-for-sale securities	9	
 	 	—	
 	 	—	
 	 	9	
 	
Other (a)	14	
 	 	—	
 	 	—	
 	 	14	
 	
Nuclear trust fund investments:	 	 	 	 	 	 	 	
Cash and cash equivalents	6	
 	 	—	
 	 	—	
 	 	6	
 	
U.S. government and federal agency obligations	54	
 	 	1	
 	 	—	
 	 	55	
 	
Federal agency mortgage-backed securities	—	
 	 	59	
 	 	—	
 	 	59	
 	
Commercial mortgage-backed securities	—	
 	 	25	
 	 	—	
 	 	25	
 	
Corporate debt securities	—	
 	 	81	
 	 	—	
 	 	81	
 	
Equity securities	280	
 	 	—	
 	 	54	
 	 	334	
 	
Foreign government fixed income securities	—	
 	 	1	
 	 	—	
 	 	1	
 	
Other trust fund investments:	 	 	 	 	 	 	 	
U.S. government and federal agency obligations	1	
 	 	—	
 	 	—	
 	 	1	
 	
Derivative assets:	 	 	 	 	 	 	 	
Commodity contracts	622	
 	 	1,449	
 	 	149	
 	 	2,220	
 	
Total assets	$	986	
 	 	$	1,616	
 	 	$	220	
 	 	$	2,822	
 	
Derivative liabilities:	 	 	 	 	 	 	 	
Commodity contracts	868	
 	 	1,036	
 	 	182	
 	 	2,086	
 	
Interest rate contracts	—	
 	 	128	
 	 	—	
 	 	128	
 	
Total liabilities	$	868	
 	 	$	1,164	
 	 	$	182	
 	 	$	2,214	
 	
(a) Primarily consists of mutual funds held in rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.
There were no transfers during the three and nine months ended September 30, 2016, and 2015 between Levels 1 and 2. The following tables reconcile, for the three and nine months ended September 30, 2016, and 2015, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, at least annually, using significant unobservable inputs:

 	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)	
 	Three months ended September 30, 2016	 	Nine months ended September 30, 2016	
(In millions)	Debt Securities	 	Trust Fund Investments	 	Derivatives(a)	 	Total	 	Debt Securities	 	Trust Fund Investments	 	Derivatives(a)	 	Total	
Beginning balance	$	16	
 	 	$	51	
 	 	$	7	
 	 	$	74	
 	 	$	17	
 	 	$	54	
 	 	$	(33	)	 	$	38	
 	
Total gains/(losses) — realized/unrealized:	 	 	 	 	 	 	

 	
 	
Included in earnings	—	
 	 	—	
 	 	2	
 	 	2	
 	 	—	
 	 	—	
 	 	9	
 	 	9	
 	
Included in OCI	1	
 	 	—	
 	 	—	
 	 	1	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	
Included in nuclear decommissioning obligation	—	
 	 	3	
 	 	—	
 	 	3	
 	 	—	
 	 	(1	)	 	—	
 	 	(1	)	
Purchases	—	
 	 	—	
 	 	(26	)	 	(26	)	 	—	
 	 	1	
 	 	3	
 	 	4	
 	
Transfers into Level 3 (b)	—	
 	 	—	
 	 	(12	)	 	(12	)	 	—	
 	 	—	
 	 	(5	)	 	(5	)	
Transfers out of Level 3 (b)	—	
 	 	—	
 	 	3	
 	 	3	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	
Ending balance as of September 30, 2016	$	17	
 	 	$	54	
 	 	$	(26	)	 	$	45	
 	 	$	17	
 	 	$	54	
 	 	$	(26	)	 	$	45	
 	
Gains/(losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2016	$	—	
 	 	$	—	
 	 	$	1	
 	 	$	1	
 	 	$	—	
 	 	$	—	
 	 	$	(14	)	 	$	(14	)	
 	 	
(a)	Consists of derivative assets and liabilities, net.	
 	 	
(b)	Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.	

22

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)	
 	Three months ended September 30, 2015	 	Nine months ended September 30, 2015	
(In millions)	Debt Securities	 	Other	 	Trust Fund Investments	 	Derivatives(a)	 	Total	 	Debt Securities	 	Other	 	Trust Fund Investments	 	Derivatives(a)	 	Total	
Beginning balance	$	18	
 	 	$	—	
 	 	$	55	
 	 	$	49	
 	 	$	122	
 	 	$	18	
 	 	$	11	
 	 	$	52	
 	 	$	80	
 	 	$	161	
 	
Total losses — realized/unrealized:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Included in earnings	—	
 	 	—	
 	 	—	
 	 	(17	)	 	(17	)	 	—	
 	 	(11	)	 	—	
 	 	(95	)	 	(106	)	
Included in nuclear decommissioning obligations	—	
 	 	—	
 	 	(6	)	 	—	
 	 	(6	)	 	—	
 	 	—	
 	 	(4	)	 	—	
 	 	(4	)	
Purchases	—	
 	 	—	
 	 	—	
 	 	9	
 	 	9	
 	 	—	
 	 	—	
 	 	1	
 	 	44	
 	 	45	
 	
Transfers into Level 3  (b)	—	
 	 	—	
 	 	—	
 	 	(10	)	 	(10	)	 	—	
 	 	—	
 	 	—	
 	 	1	
 	 	1	
 	
Transfers out of Level 3  (b)	—	
 	 	—	
 	 	—	
 	 	2	
 	 	2	
 	 	—	
 	 	—	
 	 	—	
 	 	3	
 	 	3	
 	
Ending balance as of September 30, 2015	$	18	
 	 	$	—	
 	 	$	49	
 	 	$	33	
 	 	$	100	
 	 	$	18	
 	 	$	—	
 	 	$	49	
 	 	$	33	
 	 	$	100	
 	
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2015	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	(9	)	 	$	(9	)	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	(37	)	 	$	(37	)	
 	 	
(a)	Consists of derivative assets and liabilities, net.	
 	 	
(b)	Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.	

Derivative Fair Value Measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of September 30, 2016, contracts valued with prices provided by models and other valuation techniques make up 9% of the total derivative assets and 9% of the total derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial power and physical coal executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power and coal location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.

23

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of September 30, 2016 and December 31, 2015:

 	Significant Unobservable Inputs	
 	September 30, 2016	
 	Fair Value	 	 	 	Input/Range	
 	Assets	 	Liabilities	 	Valuation Technique	 	Significant Unobservable Input	 	Low	 	High	 	Weighted Average	
 	(In millions)	
Power Contracts	$	53	
 	 	$	78	
 	 	Discounted Cash Flow	 	Forward Market Price (per MWh)	 	$	11	
 	 	$	81	
 	 	$	27	
 	
Coal Contracts	—	
 	 	5	
 	 	Discounted Cash Flow	 	Forward Market Price (per ton)	 	44	
 	 	44	
 	 	44	
 	
FTRs	54	
 	 	50	
 	 	Discounted Cash Flow	 	Auction Prices (per MWh)	 	(63	)	 	55	
 	 	—	
 	
 	$	107	
 	 	$	133	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Significant Unobservable Inputs	
 	December 31, 2015	
 	Fair Value	 	 	 	Input/Range	
 	Assets	 	Liabilities	 	Valuation Technique	 	Significant Unobservable Input	 	Low	 	High	 	Weighted Average	
 	(In millions)	
Power Contracts	$	86	
 	 	$	100	
 	 	Discounted Cash Flow	 	Forward Market Price (per MWh)	 	$	10	
 	 	$	92	
 	 	$	27	
 	
Coal Contracts	—	
 	 	12	
 	 	Discounted Cash Flow	 	Forward Market Price (per ton)	 	28	
 	 	45	
 	 	35	
 	
FTRs	63	
 	 	70	
 	 	Discounted Cash Flow	 	Auction Prices (per MWh)	 	(98	)	 	87	
 	 	—	
 	
 	$	149	
 	 	$	182	
 	 	 	 	 	 	 	 	 	 	 	
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of September 30, 2016 and December 31, 2015:

Significant Unobservable Input	 	Position	 	Change In Input	 	Impact on Fair Value Measurement	
Forward Market Price Power/Coal	 	Buy	 	Increase/(Decrease)	 	Higher/(Lower)	
Forward Market Price Power/Coal	 	Sell	 	Increase/(Decrease)	 	Lower/(Higher)	
FTR Prices	 	Buy	 	Increase/(Decrease)	 	Higher/(Lower)	
FTR Prices	 	Sell	 	Increase/(Decrease)	 	Lower/(Higher)	
The fair value of each contract is discounted using a risk-free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of September 30, 2016, the credit reserve resulted in a $2 million decrease in fair value, which is composed of a $3 million gain in OCI and a $5 million loss in operating revenue and cost of operations. As of September 30, 2015, the credit reserve resulted in a $7 million increase in fair value, which was composed of a $4 million gain in OCI and a $3 million gain in operating revenues and cost of operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2015 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities.

24

Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 2015 Form 10-K. As of September 30, 2016, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $635 million with net exposure of $607 million. NRG held collateral (cash and letters of credit) against those positions of $45 million. Approximately 79% of the Company's exposure before collateral is expected to roll off by the end of 2017. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.

 	Net Exposure (a)	
Category by Industry Sector	(% of Total)	
Financial institutions	33	%	
Utilities, energy merchants, marketers and other	42	
 	
ISOs	25	
 	
Total as of September 30, 2016	100	%	

 	 	 	
 	Net Exposure (a)	
Category by Counterparty Credit Quality	(% of Total)	
Investment grade	90	%	
Non-rated (b)	3	
 	
Non-investment grade	7	
 	
Total as of September 30, 2016	100	%	
 	 	
(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.	
 	 	
(b)	For non-rated counterparties, a significant portion are related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings.	
NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $295 million as of September 30, 2016. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, wind and solar PPAs, and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates its credit exposure for these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of September 30, 2016, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 billion, including $2.6 billion related to assets of NRG Yield, Inc., for the next five years. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations and other technology and market factors, which NRG is unable to predict. In the case of the coal supply agreement, NRG holds a lien against the underlying asset, which significantly reduces the risk of loss.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve commercial, industrial and governmental/institutional customers and the Mass market. Retail credit risk results when a customer fails to pay for products or services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of September 30, 2016, the Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.

25

Note 5 — Nuclear Decommissioning Trust Fund 
This footnote should be read in conjunction with the complete description under Note 6, Nuclear Decommissioning Trust Fund , to the Company's 2015 Form 10-K.
NRG's Nuclear Decommissioning Trust Fund assets are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980,  Regulated Operations , because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to nuclear decommissioning trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.

 	As of September 30, 2016	 	As of December 31, 2015	
(In millions, except otherwise noted)	Fair Value	 	Unrealized Gains	 	Unrealized Losses	 	Weighted-average Maturities (In years)	 	Fair Value	 	Unrealized Gains	 	Unrealized Losses	 	Weighted-average Maturities (In years)	
Cash and cash equivalents	$	24	
 	 	$	—	
 	 	$	—	
 	 	—	
 	 	$	6	
 	 	$	—	
 	 	$	—	
 	 	—	
 	
U.S. government and federal agency obligations	52	
 	 	4	
 	 	—	
 	 	11	
 	 	55	
 	 	1	
 	 	—	
 	 	11	
 	
Federal agency mortgage-backed securities	68	
 	 	2	
 	 	—	
 	 	25	
 	 	59	
 	 	1	
 	 	—	
 	 	25	
 	
Commercial mortgage-backed securities	17	
 	 	—	
 	 	1	
 	 	26	
 	 	25	
 	 	—	
 	 	2	
 	 	28	
 	
Corporate debt securities	87	
 	 	3	
 	 	1	
 	 	11	
 	 	81	
 	 	1	
 	 	1	
 	 	10	
 	
Equity securities	355	
 	 	213	
 	 	—	
 	 	—	
 	 	334	
 	 	199	
 	 	—	
 	 	—	
 	
Foreign government fixed income securities	2	
 	 	—	
 	 	—	
 	 	9	
 	 	1	
 	 	—	
 	 	—	
 	 	9	
 	
Total	$	605	
 	 	$	222	
 	 	$	2	
 	 	 	 	$	561	
 	 	$	202	
 	 	$	3	
 	 	 	
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.

 	Nine months ended September 30,	
 	2016	 	2015	
 	(In millions)	
Realized gains	$	7	
 	 	$	14	
 	
Realized losses	3	
 	 	10	
 	
Proceeds from sale of securities	354	
 	
 	499	

26

Note 6 — Accounting for Derivative Instruments and Hedging Activities 
This footnote should be read in conjunction with the complete description under Note 5, Accounting for Derivative Instruments and Hedging Activities , to the Company's 2015 Form 10-K.
Energy-Related Commodities
As of September 30, 2016, NRG had energy-related derivative instruments extending through 2027. The Company marks these derivatives to market through the statement of operations.
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of September 30, 2016, the Company had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 2032, most of which are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of September 30, 2016 and December 31, 2015. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.

 	 	Total Volume	
 	 	September 30, 2016	 	December 31, 2015	
Category	Units	(In millions)	
Emissions	Short Ton	1	
 	 	1	
 	
Coal	Short Ton	29	
 	 	35	
 	
Natural Gas	MMBtu	73	
 	 	293	
 	
Oil	Barrel	—	
 	 	1	
 	
Power	MWh	(35	)	 	(74	)	
Capacity	MW/Day	(1	)	 	(1	)	
Interest	Dollars	$	3,219	
 	 	$	2,326	
 	
Equity	Shares	1	
 	 	1	
 	
The decrease in the natural gas position was primarily the result of settlement of generation and retail hedge positions. The increase in the interest rate position was primarily the result of entering into new interest rate swaps to hedge the Term Loan Facility, as described in Note 8,  Debt and Capital Leases .
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:

 	Fair Value	
 	Derivative Assets	 	Derivative Liabilities	
 	September 30, 2016	 	December 31, 2015	 	September 30, 2016	 	December 31, 2015	
 	(In millions)	
Derivatives designated as cash flow hedges:	 	 	 	 	 	
 	 	
Interest rate contracts current	$	—	
 	 	$	—	
 	 	$	31	
 	
 	$	42	
 	
Interest rate contracts long-term	1	
 	 	—	
 	 	99	
 	
 	68	
 	
Total derivatives designated as cash flow hedges	1	
 	 	—	
 	 	130	
 	
 	110	
 	
Derivatives not designated as cash flow hedges:	

Interest rate contracts current	—	
 	 	—	
 	 	8	
 	
 	5	
 	
Interest rate contracts long-term	6	
 	 	—	
 	 	25	
 	
 	13	
 	
Commodity contracts current	964	
 	 	1,915	
 	 	930	
 	
 	1,674	
 	
Commodity contracts long-term	249	
 	 	305	
 	 	351	
 	
 	412	
 	
Total derivatives not designated as cash flow hedges	1,219	
 	 	2,220	
 	 	1,314	
 	
 	2,104	
 	
Total derivatives	$	1,220	
 	
 	$	2,220	
 	 	$	1,444	
 	
 	$	2,214	

27

The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:

 	 	Gross Amounts Not Offset in the Statement of Financial Position	
 	 	Gross Amounts of Recognized Assets / Liabilities	 	Derivative Instruments	 	Cash Collateral (Held) / Posted	 	Net Amount	
As of September 30, 2016	 	(In millions)	
Commodity contracts:	 	 	 	 	 	 	 	 	
Derivative assets	 	$	1,213	
 	 	$	(1,027	)	 	$	(23	)	 	$	163	
 	
Derivative liabilities	 	(1,281	)	 	1,027	
 	 	121	
 	 	(133	)	
Total commodity contracts	 	(68	)	 	—	
 	 	98	
 	 	30	
 	
Interest rate contracts:	 	 	 	 	 	 	 	 	
Derivative assets	 	7	
 	 	(4	)	 	—	
 	 	3	
 	
Derivative liabilities	 	(163	)	 	4	
 	 	—	
 	 	(159	)	
Total interest rate contracts	 	(156	)	 	—	
 	 	—	
 	 	(156	)	
Total derivative instruments	 	$	(224	)	 	$	—	
 	 	$	98	
 	 	$	(126	)	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Gross Amounts Not Offset in the Statement of Financial Position	
 	 	Gross Amounts of Recognized Assets / Liabilities	 	Derivative Instruments	 	Cash Collateral (Held) / Posted	 	Net Amount	
As of December 31, 2015	 	(In millions)	
Commodity contracts:	 	 	 	 	 	 	 	
 	
Derivative assets	 	$	2,220	
 	 	$	(1,616	)	 	$	(113	)	 	$	491	
 	
Derivative liabilities	 	(2,086	)	 	1,616	
 	 	271	
 	 	(199	)	
Total commodity contracts	 	134	
 	 	—	
 	 	158	
 	 	292	
 	
Interest rate contracts:	 	 	 	 	 	 	 	
 	
Derivative liabilities	 	(128	)	 	—	
 	 	—	
 	 	(128	)	
Total derivative instruments	 	$	6	
 	 	$	—	
 	 	$	158	
 	
 	$	164	
 	
Accumulated Other Comprehensive Loss
The following table summarizes the effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:

 	Three months ended September 30, 2016	 	Nine months ended September 30, 2016	
 	Energy Commodities	 	Interest Rate	 	Total	 	Energy Commodities	 	Interest Rate	 	Total	
 	(In millions)	
Accumulated OCI beginning balance	$	—	
 	 	$	(165	)	 	$	(165	)	 	$	—	
 	 	$	(101	)	 	$	(101	)	
Reclassified from accumulated OCI to income:	 	 	 	 	 	 	 	 	 	 	 	
Due to realization of previously deferred amounts	—	
 	 	2	
 	 	2	
 	 	—	
 	 	12	
 	 	12	
 	
Mark-to-market of cash flow hedge accounting contracts	—	
 	 	32	
 	 	32	
 	 	—	
 	 	(42	)	 	(42	)	
Accumulated OCI ending balance, net of $28 tax	$	—	
 	 	$	(131	)	 	$	(131	)	
 	$	—	
 	
 	$	(131	)	 	$	(131	)	
Losses expected to be realized from OCI during the next 12 months, net of $4 tax	$	—	
 	 	$	17	
 	 	$	17	
 	 	$	—	
 	 	$	17	
 	 	$	17	

28

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Three months ended September 30, 2015	 	Nine months ended September 30, 2015	
 	Energy Commodities	 	Interest Rate	 	Total	 	Energy Commodities	 	Interest Rate	 	Total	
 	(In millions)	
Accumulated OCI beginning balance	$	(1	)	 	$	(62	)	 	$	(63	)	 	$	(1	)	 	$	(67	)	 	$	(68	)	
Reclassified from accumulated OCI to income:	 	 	 	 	 	 	 	 	 	 	 	
Due to realization of previously deferred amounts	1	
 	 	3	
 	 	4	
 	 	1	
 	 	7	
 	 	8	
 	
Mark-to-market of cash flow hedge accounting contracts	—	
 	 	(33	)	 	(33	)	 	—	
 	 	(32	)	 	(32	)	
Accumulated OCI ending balance, net of $54 tax	$	—	
 	 	$	(92	)	 	$	(92	)	
 	$	—	
 	
 	$	(92	)	 	$	(92	)	
Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts. There was no ineffectiveness for the three and nine months ended September 30, 2016, and 2015.
Impact of Derivative Instruments on the Statements of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period consolidated results of operations.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations. The effect of energy commodity contracts is included within operating revenues and cost of operations and the effect of interest rate contracts is included in interest expense.

 	Three months ended September 30,	 	Nine months ended September 30,	
 	2016	 	2015	 	2016	 	2015	
Unrealized mark-to-market results	(In millions)	
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(44	)	 	$	(29	)	 	$	(182	)	 	$	(179	)	
Reversal of acquired gain positions related to economic hedges	(19	)	 	(33	)	 	(47	)	 	(83	)	
Net unrealized (losses)/gains on open positions related to economic hedges	(121	)	 	55	
 	 	(19	)	 	(26	)	
Total unrealized mark-to-market losses for economic hedging activities	(184	)	 	(7	)	 	(248	)	 	(288	)	
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	3	
 	 	2	
 	 	13	
 	 	(34	)	
Reversal of acquired gain positions related to trading activity	—	
 	 	(1	)	 	—	
 	 	(13	)	
Net unrealized (losses)/gains on open positions related to trading activity	(8	)	 	(2	)	 	14	
 	 	—	
 	
Total unrealized mark-to-market (losses)/gains for trading activity	(5	)	 	(1	)	 	27	
 	 	(47	)	
Total unrealized losses	$	(189	)	 	$	(8	)	 	$	(221	)	 	$	(335	)	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Three months ended September 30,	 	Nine months ended September 30,	
 	2016	 	2015	 	2016	 	2015	
 	(In millions)	
Unrealized (losses)/gains included in operating revenues	$	(84	)	 	$	34	
 	 	$	(565	)	 	$	(212	)	
Unrealized (losses)/gains included in cost of operations	(105	)	 	(42	)	 	344	
 	 	(123	)	
Total impact to statement of operations — energy commodities	$	(189	)	 	$	(8	)	 	$	(221	)	 	$	(335	)	
Total impact to statement of operations — interest rate contracts	$	9	
 	 	$	(9	)	 	$	(9	)	 	$	12	
 	
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.

29

For the nine months ended September 30, 2016, the $19 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of ERCOT heat rate due to ERCOT heat rate contraction, partially offset by an increase in value of forward sales of PJM electricity due to decreases in PJM power prices.
For the nine months ended September 30, 2015, the $26 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of ERCOT electricity and coal due to decreases in ERCOT power and coal prices partially offset by an increase in value of forward sales of PJM electricity due to decreases in PJM power prices.
During 2016, the Company has been undergoing the process of closing out and financially settling certain open positions with counterparties. The closure and financial settlements with these counterparties were necessary to manage the increase in collateral posting requirements following rating agency downgrades for GenOn and to reduce expected collateral costs associated with exchange cleared hedge transactions. GenOn realized approximately $38 million due to the closure and financial settlement of all open positions with one of GenOn's counterparties during the second quarter of 2016, for which $18 million, $19 million and $1 million would have been realized during the remainder of 2016, 2017 and 2018, respectively. During the third quarter of 2016, GenOn realized $98 million due to the closure and financial settlement of certain positions with an additional counterparty for which $82 million, $13 million and $3 million would have otherwise been realized in 2017, 2018, and 2019, respectively. GenOn has entered into additional transactions with NRG Power Marketing LLC and an external counterparty in order to re-hedge the positions settled with certain counterparties.
Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of September 30, 2016, was $73 million. The collateral required for contracts with credit rating contingent features as of September 30, 2016, was $42 million. The Company is also a party to certain marginable agreements where NRG has a net liability position, but the counterparty has not called for the collateral due, which was approximately $10 million as of September 30, 2016.
See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.
Note 7 — Impairments 

Rockford — As described in Note 3, Business Acquisitions and Dispositions, on May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016, to reduce the carrying amount of the assets held for sale to the fair market value.

Mandalay and Ormond Beach — On May 26, 2016, the CPUC rejected a multi-year resource adequacy contract between Mandalay and SCE. Also during the second quarter of 2016, the Statewide Advisory Committee on Cooling Water Intake Structures, or SACCWIS, issued a draft April 2016 Report noting that CAISO plans to continue to assume in its transmission studies that Ormond Beach will not operate after December 31, 2020, the deadline for Ormond Beach compliance with California regulations to mitigate once-through cooling (OTC) impacts. The Company does not anticipate that contracts of sufficient value can be secured to support the significant investment required to design, permit, construct and operate measures required for OTC compliance. As a result, on May 6, 2016, the Company notified SACCWIS that it does not expect to continue to operate Ormond Beach beyond 2020. Additionally, during the second quarter of 2016, CAISO issued its Local Capacity Requirements report for 2017 indicating unfavorable changes within the local reliability areas in which both Mandalay and Ormond Beach are located. The culmination of these events were considered to be indicators of impairment and as a result, the Company performed impairment tests for the Mandalay and Ormond Beach assets under ASC 360,  Property, Plant and Equipment . Based on the results of the impairment tests, the Company determined that the carrying amount of these assets was higher than the estimated future net cash flows expected to be generated by the respective assets and that the Mandalay and Ormond Beach assets were impaired. The fair value of the Mandalay and Ormond Beach operating units was determined using the income approach which utilizes estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company measured the impairment losses as the difference between the carrying amount of the Mandalay and Ormond Beach operating units and the present value of the estimated future net cash flows for each respective operating unit. The Company recorded an impairment loss of $16 million and $43 million for Mandalay and Ormond Beach, respectively, during the quarter ended June 30, 2016.

30

Other Impairments — During the second quarter of 2016, the Company recorded impairment losses for intangible assets of $8 million in connection with the Company's strategic change in its residential solar business as well as $10 million of deferred marketing expenses. In addition, the Company also recorded an impairment loss of $17 million to record certain previously purchased solar panels at fair market value. During the third quarter of 2016, the Company recorded an additional $8 million in impairments losses related to investments and $8 million in other impairments.

Petra Nova Parish Holdings —During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $140 million.

  

31

Note 8 — Debt and Capital Leases 
This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2015 Form 10-K. Long-term debt and capital leases consisted of the following:

(In millions, except rates)	 	September 30, 2016	 	December 31, 2015	 	September 30, 2016 interest rate %  (a)	
 	 	 	
Recourse debt:	 	 	 	 	 	 	
Senior notes, due 2018	 	$	584	
 	 	$	1,039	
 	 	7.625	
Senior notes, due 2020	 	—	
 	 	1,058	
 	 	8.250	
Senior notes, due 2021	 	399	
 	 	1,128	
 	 	7.875	
Senior notes, due 2022	 	992	
 	 	1,100	
 	 	6.250	
Senior notes, due 2023	 	869	
 	 	936	
 	 	6.625	
Senior notes, due 2024	 	733	
 	 	904	
 	 	6.250	
Senior notes, due 2026	 	1,000	
 	 	—	
 	 	7.250	
Senior notes, due 2027	 	1,250	
 	 	—	
 	 	6.625	
Term loan facility, due 2018	 	—	
 	 	1,964	
 	 	L+2.00	
Term loan facility, due 2023	 	1,886	
 	 	—	
 	 	L+2.75	
Tax-exempt bonds	 	455	
 	 	455	
 	 	4.125 - 6.00	
Subtotal NRG recourse debt	 	8,168	
 	 	8,584	

Non-recourse debt:	 	 	 	 	 	 	
GenOn senior notes	 	1,922	
 	 	1,956	
 	 	7.875 - 9.875	
GenOn Americas Generation senior notes	 	747	
 	 	752	
 	 	8.500 - 9.125	
GenOn other	 	52	
 	 	56	
 	 	 	
Subtotal GenOn debt (non-recourse to NRG)	 	2,721	
 	 	2,764	
 	 	 	
NRG Yield Operating LLC Senior Notes, due 2024	 	500	
 	 	500	
 	 	5.375	
NRG Yield Operating LLC Senior Notes, due 2026	 	350	
 	 	—	
 	 	5.000	
NRG Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019	 	—	
 	 	306	
 	 	L+2.75	
NRG Yield Inc. Convertible Senior Notes, due 2019	 	334	
 	 	330	
 	 	3.500	
NRG Yield Inc. Convertible Senior Notes, due 2020	 	270	
 	 	266	
 	 	3.250	
El Segundo Energy Center, due 2023	 	443	
 	 	485	
 	 	L+1.625 - L+2.25	
Marsh Landing, due 2017 and 2023	 	385	
 	 	418	
 	 	L+1.175 - L+1.875	
Alta Wind I - V lease financing arrangements, due 2034 and 2035	 	978	
 	 	1,002	
 	 	5.696 - 7.015	
Walnut Creek, term loans due 2023	 	322	
 	 	351	
 	 	L+1.625	
Tapestry, due 2021	 	175	
 	 	181	
 	 	L+1.625	
CVSR, due 2037	 	771	
 	 	793	
 	 	2.339 - 3.775	
CVSR HoldCo, due 2037	 	199	
 	 	—	
 	 	4.680	
Alpine, due 2022	 	147	
 	 	154	
 	 	L+1.750	
Energy Center Minneapolis, due 2017 and 2025	 	98	
 	 	108	
 	 	5.95 - 7.25	
Viento, due 2023	 	183	
 	 	189	
 	 	L+2.75	
NRG Yield - other	 	549	
 	 	573	
 	 	various	
Subtotal NRG Yield debt (non-recourse to NRG)	 	5,704	
 	 	5,656	
 	 	 	
Ivanpah, due 2033 and 2038	 	1,135	
 	 	1,149	
 	 	2.285 - 4.256	
Agua Caliente, due 2037	 	864	
 	 	879	
 	 	2.395 - 3.633	
Dandan, due 2033	 	100	
 	 	98	
 	 	L+2.25	
Peaker bonds, due 2019	 	—	
 	 	72	
 	 	L+1.07	
Cedro Hill, due 2025	 	165	
 	 	103	
 	 	L+1.75	
Midwest Generation, due 2019	 	234	
 	 	—	
 	 	4.390	
NRG Other	 	320	
 	 	315	
 	 	various	
Subtotal other NRG non-recourse debt	 	2,818	
 	 	2,616	
 	 	 	
Subtotal all non-recourse debt	 	11,243	
 	 	11,036	
 	 	 	
Subtotal long-term debt (including current maturities)	 	19,411	
 	
 	19,620	
 	 	 	
Capital leases	 	11	
 	 	16	
 	 	various	
Subtotal long-term debt and capital leases (including current maturities)	 	19,422	
 	
 	19,636	
 	 	 	
Less current maturities	 	1,221	
 	
 	481	
 	 	 	
Less debt issuance costs	 	183	
 	 	172	
 	 	 	
Total long-term debt and capital leases	 	$	18,018	
 	
 	$	18,983	
 	 	 	
(a) As of September 30, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento Funding II term loan, which is 6 month LIBOR plus x%, and the Alpine Term Loan, the NRG Marsh Landing term loan, the Walnut Creek term loan, and 2016 Term Loan Facility, which are 1 month LIBOR plus x%.

32

NRG Recourse Debt
Senior Notes
Issuance of 2026 Senior Notes
On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026. The proceeds from the issuance of the 2026 Senior Notes were utilized to redeem a portion of the Senior Notes discussed below.
Issuance of 2027 Senior Notes
On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021.
Senior Notes Repurchases
During the nine months ended September 30, 2016, the Company repurchased $2.6 billion in aggregate principal of its Senior Notes in the open market for $2.7 billion, which included accrued interest of $67 million. In connection with the repurchases, a $94 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $15 million.

 	Principal Repurchased	 	Cash Paid (a)                          	 	Average Early Redemption Percentage	
Amount in millions, except rates	 	 	 	 	 	
7.625% senior notes due 2018	$	455	
 	 	$	502	
 	 	107.95	%	
8.250% senior notes due 2020	1,058	
 	 	1,129	
 	 	103.12	%	
7.875% senior notes due 2021	729	
 	 	771	
 	 	104.02	%	
6.250% senior notes due 2022	108	
 	 	105	
 	 	94.73	%	
6.625% senior notes due 2023	67	
 	 	64	
 	 	94.13	%	
6.250% senior notes due 2024	171	
 	 	163	
 	 	94.52	%	
Total at September 30, 2016	$	2,588	
 	 	$	2,734	
 	 	 	
7.625% senior notes due 2018 (b)	186	
 	 	204	
 	 	107.75	%	
7.875% senior notes due 2021 (b)	193	
 	 	207	
 	 	103.94	%	
Total at November 4, 2016	$	2,967	
 	 	$	3,145	
 	 	 	
(a) Includes payment for accrued interest
(b) Redemptions financed by cash on hand
Senior Credit Facility
On June 30, 2016, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility and Revolving Credit Facility with a new senior secured facility, or the 2016 Senior Credit Facility, which includes the following:
 	 	
•	A $1.9 billion term loan facility, or the 2016 Term Loan Facility, with a maturity date of June 30, 2023, which will pay interest at a rate of LIBOR plus 2.75%, with a LIBOR floor of 0.75%. The debt was issued at 99.50% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the 2016 Term Loan Facility will consist of 0.25% of principal per quarter, with the remainder due at maturity. The proceeds of the new term loan facility as well as cash on hand were used to repay the existing 2018 Term Loan Facility balance outstanding. A $21 million loss on extinguishment of the Term Loan Facility was recorded during the second quarter of 2016, which consisted of the write-off of previously deferred financing costs.	

•	The 2016 Revolving Credit Facility, which includes a $289 million revolving senior credit facility, or the Tranche A Revolving Facility, with a maturity date of July 1, 2018 and a $2.2 billion revolving senior credit facility, or the Tranche B Revolving Facility, with a maturity date of June 30, 2021 will pay interest at a rate of LIBOR plus 2.25%.	

33

The 2016 Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, and certain other subsidiaries, including GenOn, NRG Yield, Inc. and their respective subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of the 2016 Senior Credit Facility's lenders.

The 2016 Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including GenOn, NRG Yield, Inc. and their respective subsidiaries, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries.
Non-recourse Debt
GenOn Senior Notes
As of September 30, 2016, $703 million of GenOn's Senior Notes outstanding are classified as current within the consolidated balance sheet as they mature on June 15, 2017. Based on current projections, GenOn is not expected to have sufficient liquidity, exclusive of cash subject to the restrictions under the GenOn Mid-Atlantic and REMA operating leases, to make this principal payment as it becomes due. As a result of these factors, there is no assurance GenOn will continue as a going concern.
GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the Senior Notes, potential sales of certain generating assets as well as the possibility of a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During the second quarter of 2016, GenOn appointed two independent directors as part of this process. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility
NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. At September 30, 2016, there was $64 million of letters of credit issued under the revolving credit facility and no borrowing outstanding on the revolver.
Thermal Financing
On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Yield, Inc. received proceeds of $125 million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility for an additional $70 million of notes. The Series D Notes are, and the additional notes, if issued, will be secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries. NRG Energy Center Minneapolis LLC distributed the proceeds of the Series D Notes to NRG Thermal LLC, who in turn distributed the proceeds to NRG Yield Operating LLC to be utilized for general corporate purposes, including potential acquisitions.
Project Financings
Peakers
In June 2002, NRG Peaker Finance Company LLC, or Peakers, an indirect wholly-owned subsidiary of NRG, issued bonds due June 2019. These notes were also secured by, among other things, substantially all of the assets of and membership interests in Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC.
On June 30, 2016, in contemplation of the sale of Rockford as further discussed in Note 3, Business Acquisitions and Dispositions , NRG Peaker Finance Company LLC elected to redeem all of the outstanding bonds at a redemption price equal to the principal amount plus a redemption premium, accrued and unpaid interest, swap breakage, and other fees, totaling approximately $85 million in connection with the removal of NRG Rockford LLC, and NRG Rockford II, LLC from the peaker financing collateral package. The Company recognized a $3 million loss on extinguishment of the debt related to the write-off of unamortized discount during the second quarter of 2016. On July 12, 2016, NRG completed the sale of the Rockford generating stations.
High Lonesome Mesa Facility
Prior to the Company's acquisition of EME, an intercompany tax credit agreement related to the High Lonesome Mesa facility was terminated. The termination resulted in an event of default under the project financing arrangement. The Company received additional default notices for various items. The facility is secured by the assets of High Lonesome Mesa and is non-recourse to NRG.

34

On November 3, 2015, the lender sent a notice of acceleration and indicated that it would accept the Company's interest in the assets in lieu of repayment. On January 27, 2016, High Lonesome Mesa, LLC, or HLM, filed at FERC for approval to transfer 100% of the ownership interests in HLM to subsidiaries of the lien holders, Macquarie Bank Limited and Hannon Armstrong Capital, LLC. On March 2, 2016 HLM received FERC approval and on March 31, 2016 the Company transferred 100% of its interest in HLM to the lien holders and deconsolidated HLM.
Dandan Financing
In December 2013, NRG, through its wholly-owned subsidiary, NRG Solar Dandan LLC, or Dandan, entered into a credit agreement with a bank, or the Dandan Financing Agreement, for an $81 million construction loan and a $23 million cash grant loan. On January 29, 2016, the construction loan converted to a $79 million term loan with $23 million outstanding under the cash grant loan. In addition, a $4 million debt service letter of credit was issued replacing the $5 million construction letter of credit that was outstanding at year end. As of September 30, 2016, $77 million was outstanding under the term loan, $23 million was outstanding under the cash grant loan and $4 million in letters of credit in support of the project were issued.
Midwest Generation
On April 7, 2016, Midwest Generation, LLC, or MWG, entered into an agreement to sell certain quantities of unforced capacity that has cleared various PJM Reliability Pricing Model auctions to a trading counterparty for net proceeds of $253 million. MWG will continue to operate the applicable generation facilities and remains responsible for performance penalties and eligible for performance bonus payments, if any. Accordingly, MWG will continue to account for all revenues and costs as before; however, the proceeds will be recorded as a financing obligation while capacity payments by PJM to the counterparty will be reflected as debt amortization and interest expense through the end of the 2018/19 delivery year.  MWG will amortize the upfront discount to interest expense, at an effective interest rate of 4.39%, over the term of the arrangement, through June 2019. As of September 30, 2016, $234 million was outstanding.
CVSR
On July 15, 2016, CVSR Holdco LLC, the indirect owner of the CVSR project, issued $200 million of senior secured notes.  The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and NRG Yield Operating LLC, the owners of CVSR Holdco LLC, based on their pro-rata ownership. The notes were issued at par and bear an interest rate at 4.68%. Interest is payable semi-annually beginning on September 30, 2016, until the maturity date of March 31, 2037.
Capistrano Refinancing
On July 13 2016, Cedro Hill, Broken Bow and Crofton Bluffs, subsidiaries of Capistrano Wind Partners, each amended their respective credit facilities to increase borrowings to a total of $312 million and to lower their respective interest rates. The net proceeds of $87 million, were distributed to Capistrano Wind Partners and subsequently distributed to the holders of the Class B preferred equity interests of tax Capistrano Wind Partners.
NRG Yield Operating 2026 Senior Notes
On August 18, 2016, NRG Yield Operating LLC issued $350 million of senior unsecured notes, or the NRG Yield Operating 2026 Senior Notes. The NRG Yield Operating 2026 Senior Notes bear interest of 5.00% and mature on September 15, 2026. Interest on the notes is payable semi-annually on March 15 and September 15 of each year, and will commence on March 15, 2017. The Yield Operating 2026 Senior Notes are senior unsecured obligations of NRG Yield Operating LLC and are guaranteed by NRG Yield LLC, and by certain of NRG Yield Operating LLC’s wholly owned current and future subsidiaries. A portion of the proceeds from the 2026 Senior Notes was used to repay NRG Yield Operating LLC's revolving credit facility.

35

Note 9 — Variable Interest Entities, or VIEs 
Entities that are not Consolidated
NRG has interests in entities that are considered VIEs under ASC 810, Consolidation, but NRG is not considered the primary beneficiary.  NRG accounts for its interests in these entities under the equity method of accounting.
GenConn Energy LLC— Through its consolidated subsidiary, NRG Yield Operating LLC, the Company owns a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $106 million as of September 30, 2016.
Sherbino I Wind Farm LLC— NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. NRG's maximum exposure to loss is limited to its equity investment, which was $72 million as of September 30, 2016.
Entities that are Consolidated
The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies  to the Company's 2015 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $44 million as of September 30, 2016, which would be required to be funded if the arrangement were to be dissolved.
The summarized financial information for the Company's consolidated VIEs consisted of the following:

(In millions)	September 30, 2016	 	December 31, 2015	
Current assets	$	76	
 	 	$	84	
 	
Net property, plant and equipment	1,742	
 	 	1,807	
 	
Other long-term assets	945	
 	 	863	
 	
Total assets	2,763	
 	 	2,754	
 	
Current liabilities	59	
 	 	56	
 	
Long-term debt	450	
 	 	366	
 	
Other long-term liabilities	194	
 	 	179	
 	
Total liabilities	703	
 	 	601	
 	
Noncontrolling interests	562	
 	 	493	
 	
Net assets less noncontrolling interests	$	1,498	
 	 	$	1,660	

Note 10 — Changes in Capital Structure 
As of September 30, 2016, and December 31, 2015, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:

 	Issued	 	Treasury	 	Outstanding	
Balance as of December 31, 2015	416,939,950	
 	 	(102,749,908	)	 	314,190,042	
 	
Shares issued under LTIPs	643,642	
 	 	—	
 	 	643,642	
 	
Shares issued under ESPP	—	
 	 	609,094	
 	 	609,094	
 	
Balance as of September 30, 2016	417,583,592	
 	 	(102,140,814	)	 	315,442,778	
 	
Preferred Stock
On May 24, 2016, NRG entered an agreement with Credit Suisse Group to     repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The transaction resulted in a gain on redemption of $78 million, measured as the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferred stock at the time of the redemption of $304 million. This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share.

36

Employee Stock Purchase Plan
As of September 30, 2016, there were 667,819 shares of treasury stock available for issuance under the ESPP.
NRG Common Stock Dividends
The following table lists the dividends paid during the nine months ended September 30, 2016:

 	Third Quarter 2016	 	Second Quarter 2016	
 	First Quarter 2016	
Dividends per Common Share	$	0.030	
 	 	$	0.030	
 	
 	$	0.145	
 	
On October 19, 2016, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable November 15, 2016, to stockholders of record as of November 1, 2016, representing $0.12 per share on an annualized basis.
The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

Note 11 — Earnings/(Loss) Per Share 
Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner consistent with that of basic income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The reconciliation of NRG's basic and diluted earnings/(loss) per share is shown in the following table:

 	Three months ended September 30,	 	Nine months ended September 30,	
(In millions, except per share data)	2016	 	2015	 	2016	 	2015	
Basic earnings/(loss) per share attributable to NRG Energy, Inc. common stockholders	
Net income/(loss) attributable to NRG Energy, Inc.	$	402	
 	 	$	66	
 	 	$	213	
 	 	$	(68	)	
Dividends for preferred shares	—	
 	 	5	
 	 	5	
 	 	15	
 	
Gain on redemption of 2.822% redeemable perpetual preferred stock	—	
 	 	—	
 	 	(78	)	 	—	
 	
Income/(loss) available for common stockholders	$	402	
 	
 	$	61	
 	
 	$	286	
 	
 	$	(83	)	
Weighted average number of common shares outstanding - basic	316	
 	 	331	
 	
 	315	
 	 	334	
 	
Earnings/(Loss) per weighted average common share — basic	$	1.27	
 	 	$	0.18	
 	 	$	0.91	
 	 	$	(0.25	)	
Diluted earnings/(loss) per share attributable to NRG Energy, Inc. common stockholders	 	 	 	 	
Weighted average number of common shares outstanding	316	
 	 	331	
 	 	315	
 	 	334	
 	
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	1	
 	 	1	
 	 	1	
 	 	—	
 	
Total dilutive shares	317	
 	 	332	
 	 	316	
 	 	334	
 	
Earnings/(loss) per weighted average common share — diluted	$	1.27	
 	 	$	0.18	
 	 	$	0.91	
 	 	$	(0.25	)	
The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted loss per share:

 	Three months ended September 30,	 	Nine months ended September 30,	
(In millions of shares)	2016	 	2015	 	2016	 	2015	
Equity compensation plans	2	
 	 	3	
 	 	3	
 	 	6	
 	
Embedded derivative of 2.822% redeemable perpetual preferred stock	—	
 	 	16	
 	 	—	
 	 	16	
 	
Total	2	
 	 	19	
 	 	3	
 	 	22	

37

Note 12 — Segment Reporting 
The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation (previously Generation/Business), which includes generation, international and business solutions; Retail Mass (previously NRG Home Retail); Renewables (previously NRG Renew), which includes solar and wind assets; NRG Yield; and corporate activities. The Company's corporate segment includes BETM, residential solar and electric vehicle services. Effective January 1, 2016, the Company began reporting the results of its residential solar business in its corporate segment. Effective April 1, 2016, the Company began reporting the results of its international business in its Generation segment. The financial information for the three months and nine months ended September 30, 2015 has been recast to reflect the change.
On September 1, 2016, NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. On November 3, 2015, NRG Yield acquired 75% of the class B interests in NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities, from the Company. Both acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods have been recast to reflect the acquisition as if they had occurred at the beginning of the financial statement period.
NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss).

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(In millions)	Generation(a)	 	Retail Mass (a)	 	Renewables(a)	 	NRG Yield (a)	 	Corporate(a)(b)	 	Eliminations	 	Total	
Three months ended September 30, 2016	 	
Operating revenues(a)	$	2,494	
 	 	$	1,619	
 	 	$	140	
 	 	$	272	
 	 	$	40	
 	 	$	(613	)	 	$	3,952	
 	
Depreciation and amortization	193	
 	 	25	
 	 	48	
 	 	75	
 	 	16	
 	 	—	
 	 	357	
 	
Impairment losses	8	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	8	
 	
Equity in earnings/(losses) of unconsolidated affiliates	6	
 	 	—	
 	 	(4	)	 	13	
 	 	1	
 	 	—	
 	 	16	
 	
Gain on sale of assets	262	
 	 	—	
 	 	—	
 	 	—	
 	 	4	
 	 	—	
 	 	266	
 	
(Impairment loss)/gain on investment	(5	)	 	—	
 	 	1	
 	 	—	
 	 	(4	)	 	—	
 	 	(8	)	
Income/(loss) before income taxes	628	
 	 	2	
 	 	8	
 	 	60	
 	 	(252	)	 	(4	)	 	442	
 	
Net Income/(Loss)	630	
 	 	2	
 	 	11	
 	 	47	
 	
 	(293	)	 	(4	)	 	393	
 	
Net Income/(Loss) attributable to NRG Energy, Inc.	$	630	
 	 	$	2	
 	 	$	—	
 	 	$	52	
 	 	$	(317	)	 	$	35	
 	 	$	402	
 	
Total assets as of September 30, 2016	$	14,153	
 	 	$	1,601	
 	 	$	4,920	
 	 	$	8,482	
 	 	$	16,970	
 	 	$	(14,635	)	 	31,491	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	555	
 	 	$	—	
 	 	$	9	
 	 	$	2	
 	 	$	47	
 	 	$	—	
 	 	$	613	
 	
(b) Includes loss on debt extinguishment	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	(50	)	 	$	—	
 	 	$	(50	)	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(In millions)	Generation(a)	 	Retail Mass (a)	 	Renewables(a)	 	NRG Yield (a)(b)	 	Corporate(a)	 	Eliminations	 	Total	
Three months ended September 30, 2015	 	
Operating revenues(a)	$	2,726	
 	 	$	1,699	
 	 	$	124	
 	 	$	256	
 	 	$	1	
 	 	$	(372	)	 	$	4,434	
 	
Depreciation and amortization	220	
 	 	30	
 	 	46	
 	 	69	
 	 	17	
 	 	—	
 	 	382	
 	
Impairment losses	222	
 	 	36	
 	 	5	
 	 	—	
 	 	—	
 	 	—	
 	 	263	
 	
Equity in earnings/(loss) of unconsolidated affiliates	7	
 	 	—	
 	 	(2	)	 	12	
 	 	1	
 	 	6	
 	 	24	
 	
Income/(Loss) before income taxes	166	
 	 	197	
 	 	(20	)	 	40	
 	 	(276	)	 	7	
 	 	114	
 	
Net Income/(Loss)	164	
 	 	197	
 	 	(16	)	 	32	
 	 	(317	)	 	7	
 	 	67	
 	
Net Income/(Loss) attributable to NRG Energy, Inc.	$	164	
 	 	$	197	
 	 	$	(33	)	 	$	20	
 	 	$	(315	)	 	$	33	
 	 	$	66	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	309	
 	 	$	2	
 	 	$	(6	)	 	$	18	
 	 	$	49	
 	 	$	—	
 	 	$	372	
 	
(b) Includes loss on debt extinguishment	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	2	
 	 	$	—	
 	 	$	—	
 	 	$	2	

38

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(In millions)	Generation(a)	 	Retail Mass (a)	 	Renewables(a)	 	NRG Yield (a)	 	Corporate(a)(b)	 	Eliminations	 	Total	
Nine months ended September 30, 2016	 	
Operating revenues(a)	$	5,920	
 	 	$	3,868	
 	 	$	335	
 	 	$	789	
 	 	$	128	
 	 	$	(1,221	)	 	$	9,819	
 	
Depreciation and amortization	483	
 	 	80	
 	 	143	
 	 	224	
 	 	49	
 	 	—	
 	 	979	
 	
Impairment losses	84	
 	 	—	
 	 	26	
 	 	—	
 	 	13	
 	 	—	
 	 	123	
 	
Equity in earnings/(losses) of unconsolidated affiliates	1	
 	 	—	
 	 	(13	)	 	29	
 	 	3	
 	 	(7	)	 	13	
 	
Gain/(loss) on sale of assets	293	
 	 	—	
 	 	—	
 	 	—	
 	 	(78	)	 	—	
 	 	215	
 	
(Impairment loss)/gain on investment	(142	)	 	—	
 	 	1	
 	 	—	
 	 	(6	)	 	—	
 	 	(147	)	
Income/(loss) before income taxes	417	
 	 	644	
 	 	(116	)	 	136	
 	 	(815	)	 	(7	)	 	259	
 	
Net Income/(Loss)	418	
 	 	644	
 	 	(102	)	 	111	
 	 	(900	)	 	(7	)	 	164	
 	
Net Income/(Loss) attributable to NRG Energy, Inc.	$	418	
 	 	$	644	
 	 	$	(98	)	 	$	108	
 	 	$	(931	)	 	$	72	
 	 	$	213	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1,025	
 	 	$	2	
 	 	$	19	
 	 	$	6	
 	 	$	169	
 	 	$	—	
 	 	$	1,221	
 	
(b) Includes loss on debt extinguishment	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	(119	)	 	$	—	
 	 	$	(119	)	

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(In millions)	Generation(a)	 	Retail Mass (a)	 	Renewables(a)	 	NRG Yield (a)(b)	 	Corporate(a)	 	Eliminations	 	Total	
Nine months ended September 30, 2015	 	
Operating revenues(a)	$	7,345	
 	 	$	4,308	
 	 	$	305	
 	 	$	729	
 	 	$	9	
 	 	$	(1,033	)	 	$	11,663	
 	
Depreciation and amortization	681	
 	 	93	
 	 	135	
 	 	222	
 	 	42	
 	 	—	
 	 	1,173	
 	
Impairment losses	222	
 	 	36	
 	 	5	
 	 	—	
 	 	—	
 	 	—	
 	 	263	
 	
Gain on postretirement benefits curtailment	14	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	14	
 	
Equity in earnings/(losses) of unconsolidated affiliates	9	
 	 	—	
 	 	(2	)	 	19	
 	 	—	
 	 	3	
 	 	29	
 	
Income/(loss) before income taxes	216	
 	 	523	
 	 	(87	)	 	61	
 	 	(834	)	 	—	
 	 	(121	)	
Net Income/(Loss)	213	
 	 	523	
 	 	(74	)	 	53	
 	 	(793	)	 	—	
 	 	(78	)	
Net Income/(Loss) attributable to NRG Energy, Inc.	$	213	
 	 	$	523	
 	 	$	(100	)	 	$	29	
 	 	$	(765	)	 	$	32	
 	 	$	(68	)	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	853	
 	 	$	4	
 	 	$	18	
 	 	$	27	
 	 	$	131	
 	 	$	—	
 	 	$	1,033	
 	
(b) Includes loss on debt extinguishment	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	9	
 	 	$	—	
 	 	$	—	
 	 	$	9	

Note 13 — Income Taxes 
Effective Tax Rate
The income tax provision consisted of the following:

 	Three months ended September 30,	 	Nine months ended September 30,	
(In millions except otherwise noted)	2016	 	2015	 	2016	 	2015	
Income/(loss) before income taxes	$	442	
 	 	$	114	
 	 	$	259	
 	 	$	(121	)	
Income tax (benefit)/expense	49	
 	 	47	
 	 	95	
 	 	(43	)	
Effective tax rate	11.1	%	 	41.2	%	 	36.7	%	 	35.5	%	
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the change in valuation allowance, partially offset by state tax expense and tax expense attributable to consolidated partnerships.
For the three months ended September 30, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to non-deductible impairment of goodwill, partially offset by production tax credits generated from the Company's wind assets.

39

For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state tax expense and amortization of indefinite lived assets, partially offset by the change in valuation allowance.
For the nine months ended September 30, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of production tax credits generated from the Company's wind assets, partially offset by tax expense attributable to consolidated partnerships.
Uncertain Tax Benefits
As of September 30, 2016, NRG has recorded a non-current tax liability of $44 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the nine months ended September 30, 2016, NRG accrued $1 million of interest relating to the uncertain tax benefits. As of September 30, 2016, NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2009. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.
Note 14 — Commitments and Contingencies 
This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2015 Form 10-K.
Commitments
First Lien Structure — NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of September 30, 2016, hedges under the first liens were in-the-money for NRG on a counterparty aggregate basis.
Ivanpah Energy Production Guarantee — The Company's PPAs with PG&E with respect to the Ivanpah project contain provisions for contract quantity and guaranteed energy production, which require that Ivanpah units 1 and 3 deliver to PG&E no less than the guaranteed energy production amount specified in the PPAs in any period of twenty-four consecutive months, or performance measurement period, during the term of the PPAs.  If either of Ivanpah units 1 and 3 deliver less than the guaranteed energy production amount in any performance measurement period, PG&E may, at its option, declare an event of default.  The two units did not meet their guaranteed energy production amount for the initial performance measurement period.  On December 18, 2015, PG&E filed a request with the CPUC that it approve forbearance agreements relating to Ivanpah units 1 and 3.  On March 17, 2016, the CPUC adopted a resolution approving the forbearance agreements, which are final and non-appealable and in full effect. Under the forbearance agreements, PG&E agrees to refrain from taking certain actions (including declaring an event of default and invoking associated remedies) for an initial six-month period of time.  If the units meet certain production requirements during such period, then the forbearance agreements provide for a six-month extension of such period. In the third quarter of 2016, each of Ivanpah's unit 1 and unit 3 satisfied its respective production requirement for the initial six-month measurement period under the forbearance agreements.

Lignite Contract with Texas Westmoreland Coal Co. — The Company's Limestone facility utilizes a blend of coal including lignite obtained from the Jewett mine, a surface mine adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is a cost-plus arrangement with certain performance incentives and penalties. On August 18, 2016, NRG gave notice to TWCC terminating the active mining of lignite under the contract, effective on December 31, 2016.
Under the contract, TWCC continues to be responsible for reclamation activities. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $95.5 million on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.

40

Contingencies
The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
Midwest Generation Asbestos Liabilities— The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation.
Actions Pursued by MC Asset Recovery— With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings.  MC Asset Recovery is governed by a manager who is independent of NRG and GenOn.  MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings.  In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants.  In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit.  In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants.  On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. The appeal has been fully briefed by the parties. Oral argument is scheduled for December 5, 2016.
Natural Gas Litigation—GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Court of Appeals' decision and the Supreme Court granted the petition. On April 21, 2015, the Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution.  The Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On December 8, 2016, the court will hear oral argument on several motions, including plaintiffs' motion on class certification. On May 20, 2016, the U.S. District Court for the District of Nevada heard argument on the defendants' motion for summary judgment in one of the Kansas cases. On May 24, 2016, the court granted the motion for summary judgment as to the GenOn entity in one of the Kansas cases. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.

41

Energy Plus Holdings—On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena.
Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic— On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper (together, the Citizens Group) sent GenOn Mid-Atlantic a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System permits by discharging nitrogen and phosphorous in excess of the limits in each permit. On March 21, 2013, the MDE sent GenOn Mid-Atlantic a similar letter with respect to the Chalk Point and Dickerson generating facilities, threatening to sue within 60 days if the generating facilities were not brought into compliance. On June 11, 2013, the Maryland Attorney General on behalf of the MDE filed a complaint in the U.S. District Court for the District of Maryland alleging violations of the CWA and Maryland environmental laws related to water.
In August 2016, the court approved a consent decree to settle the matter. The consent decree requires: (1) improving the wastewater treatment systems at the Chalk Point and Dickerson facilities which was completed in October 2016; (2) completing supplemental environmental projects worth $1 million; and (3) paying a civil penalty of $1 million. The Company has improved the wastewater treatment systems at the Chalk Point and Dickerson facilities and paid the civil penalty of $1 million.
Midwest Generation New Source Review Litigation— In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to $37,500 per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.
In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd.
Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

42

Potomac River Environmental Investigation — In March 2013, NRG Potomac River LLC received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site.  NRG Potomac River LLC provided various responsive materials.  In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges.  DOEE has indicated it believes that penalties are appropriate in light of the violations.  NRG is currently reviewing the information provided by DOEE.
Telephone Consumer Protection Act Purported Class Actions —Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey.  The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On July 8, 2016, NRG filed a Rule 11 Motion seeking dismissal of NRG from the California case. The Rule 11 Motion was denied on August 16, 2016.
California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation.  In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR.  At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018.  In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA.  After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not.  As such, the plaintiffs have brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions.  Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints. The hearing on the demurrers is scheduled for November 9, 2016.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA.  Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering.  Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016.

Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed responsive pleadings on November 4, 2016.

43

Note 15 — Regulatory Matters 
This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2015 Form 10-K.
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
PJM Capacity Performance Appeals  — On or about July 8, 2016, four petitions were filed at the U.S. Court of Appeals for the D.C. Circuit seeking review of the FERC orders approving PJM’s Capacity Performance revisions to its forward capacity market after motions for rehearing at FERC were denied on May 10, 2016. The Company intervened in these matters on July 29, 2016. Briefing is underway. This case concerns capacity revenues already received by the Company, as well as revenues that would be received in the future.

Midwest Generation, LLC Reactive Power Compensation — On June 21, 2016, FERC issued an order directing MWG to make a compliance filing setting forth refunds for payments received in violation of its 2004 reactive power settlement or to show cause why it has not violated the settlement and ordered MWG to revise its tariff to reflect the costs of units continuing to provide reactive power or show cause why it should not be required to do so. The Commission also referred this matter to the Commission's Office of Enforcement. On June 30, 2016, MWG filed a revised tariff, and on July 22, 2016, MWG made a compliance filing as ordered by FERC. On October 13, 2016, FERC found that MWG should only be liable for refunds that accrued after bankruptcy on April 1, 2014 through June 30, 2016. The matter is still pending at the Commission's Office of Enforcement.

44

Note 16 — Environmental Matters 
This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2015 Form 10-K.
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is facing new requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows.
The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO 2  budgets for four states including Texas and (ii) ozone-season NO x  budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.
In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which limits had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of  Michigan v. EPA , and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Water
In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of September 30, 2016.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2016 through 2020 required to comply with environmental laws will be approximately $328 million, which includes $76 million for GenOn and $234 million for Midwest Generation. These costs, the majority of which will be expended by the end of 2016, are primarily associated with (i) DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS and (ii) MATS compliance at the Avon Lake facility.

45

Note 17 — Condensed Consolidating Financial Information 
As of September 30, 2016, the Company had outstanding $5.8 billion of Senior Notes due from 2018 - 2027, as shown in Note 8,  Debt and Capital Leases . These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries and NRG Yield, Inc. and its subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30, 2016:

Ace Energy, Inc.	New Genco GP, LLC	NRG Norwalk Harbor Operations Inc.	
Allied Home Warranty GP LLC	Norwalk Power LLC	NRG Operating Services, Inc.	
Allied Warranty LLC	NRG Advisory Services LLC	NRG Oswego Harbor Power Operations Inc.	
Arthur Kill Power LLC	NRG Affiliate Services Inc.	NRG PacGen Inc.	
Astoria Gas Turbine Power LLC	NRG Artesian Energy LLC	NRG Portable Power LLC	
Bayou Cove Peaking Power, LLC	NRG Arthur Kill Operations Inc.	NRG Power Marketing LLC	
BidURenergy, Inc.	NRG Astoria Gas Turbine Operations Inc.	NRG Reliability Solutions LLC	
Cabrillo Power I LLC	NRG Bayou Cove LLC	NRG Renter's Protection LLC	
Cabrillo Power II LLC	NRG Business Services LLC	NRG Retail LLC	
Carbon Management Solutions LLC	NRG Business Solutions LLC	NRG Retail Northeast LLC	
Cirro Group, Inc.	NRG Cabrillo Power Operations Inc.	NRG Rockford Acquisition LLC	
Cirro Energy Services, Inc.	NRG California Peaker Operations LLC	NRG Saguaro Operations Inc.	
Clean Edge Energy LLC	NRG Cedar Bayou Development Company, LLC	NRG Security LLC	
Conemaugh Power LLC	NRG Connected Home LLC	NRG Services Corporation	
Connecticut Jet Power LLC	NRG Connecticut Affiliate Services Inc.	NRG SimplySmart Solutions LLC	
Cottonwood Development LLC	NRG Construction LLC	NRG South Central Affiliate Services Inc.	
Cottonwood Energy Company LP	NRG Curtailment Solutions Holdings LLC	NRG South Central Generating LLC	
Cottonwood Generating Partners I LLC	NRG Curtailment Solutions, Inc	NRG South Central Operations Inc.	
Cottonwood Generating Partners II LLC	NRG Development Company Inc.	NRG South Texas LP	
Cottonwood Generating Partners III LLC	NRG Devon Operations Inc.	NRG SPV #1 LLC	
Cottonwood Technology Partners LP	NRG Dispatch Services LLC	NRG Texas C&I Supply LLC	
Devon Power LLC	NRG Distributed Generation PR LLC	NRG Texas Gregory LLC	
Dunkirk Power LLC	NRG Dunkirk Operations Inc.	NRG Texas Holding Inc.	
Eastern Sierra Energy Company LLC	NRG El Segundo Operations Inc.	NRG Texas LLC	
El Segundo Power, LLC	NRG Energy Efficiency-L LLC	NRG Texas Power LLC	
El Segundo Power II LLC	NRG Energy Efficiency-P LLC	NRG Warranty Services LLC	
Energy Alternatives Wholesale, LLC	NRG Energy Labor Services LLC	NRG West Coast LLC	
Energy Choice Solutions LLC	NRG ECOKAP Holdings LLC	NRG Western Affiliate Services Inc.	
Energy Plus Holdings LLC	NRG Energy Services Group LLC	O'Brien Cogeneration, Inc. II	
Energy Plus Natural Gas LLC	NRG Energy Services International Inc.	ONSITE Energy, Inc.	
Energy Protection Insurance Company	NRG Energy Services LLC	Oswego Harbor Power LLC	
Everything Energy LLC	NRG Generation Holdings, Inc.	RE Retail Receivables, LLC	
Forward Home Security, LLC	NRG Greenco	Reliant Energy Northeast LLC	
GCP Funding Company, LLC	NRG Home & Business Solutions LLC	Reliant Energy Power Supply, LLC	
Green Mountain Energy Company	NRG Home Services LLC	Reliant Energy Retail Holdings, LLC	
Gregory Partners, LLC	NRG Home Solutions LLC	Reliant Energy Retail Services, LLC	
Gregory Power Partners LLC	NRG Home Solutions Product LLC	RERH Holdings, LLC	
Huntley Power LLC	NRG Homer City Services LLC	Saguaro Power LLC	
Independence Energy Alliance LLC	NRG Huntley Operations Inc.	Somerset Operations Inc.	
Independence Energy Group LLC	NRG HQ DG LLC	Somerset Power LLC	
Independence Energy Natural Gas LLC	NRG Identity Protect LLC	Texas Genco Financing Corp.	
Indian River Operations Inc.	NRG Ilion Limited Partnership	Texas Genco GP, LLC	
Indian River Power LLC	NRG Ilion LP LLC	Texas Genco Holdings, Inc.	
Keystone Power LLC	NRG International LLC	Texas Genco LP, LLC	
Langford Wind Power, LLC	NRG Maintenance Services LLC	Texas Genco Operating Services, LLC	
Louisiana Generating LLC	NRG Mextrans Inc.	Texas Genco Services, LP	
Meriden Gas Turbines LLC	NRG MidAtlantic Affiliate Services Inc.	US Retailers LLC	
Middletown Power LLC	NRG Middletown Operations Inc.	Vienna Operations Inc.	
Montville Power LLC	NRG Montville Operations Inc.	Vienna Power LLC	
NEO Corporation	NRG New Roads Holdings LLC	WCP (Generation) Holdings LLC	
NEO Freehold-Gen LLC	NRG North Central Operations Inc.	West Coast Power LLC	
NEO Power Services Inc.	NRG Northeast Affiliate Services Inc.	 	

46

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

47

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2016 
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	2,424	
 	 	$	1,622	
 	 	$	—	
 	 	$	(94	)	 	$	3,952	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	1,718	
 	 	1,158	
 	 	11	
 	 	(94	)	 	2,793	
 	
Depreciation and amortization	147	
 	 	203	
 	 	7	
 	 	—	
 	 	357	
 	
Impairment losses	8	
 	 	—	
 	 	—	
 	 	—	
 	 	8	
 	
Selling, general and administrative	114	
 	 	105	
 	 	63	
 	 	—	
 	 	282	
 	
Acquisition-related transaction and integration costs	—	
 	 	1	
 	 	(1	)	 	—	
 	 	—	
 	
Development activity expenses	—	
 	 	12	
 	 	11	
 	 	—	
 	 	23	
 	
Total operating costs and expenses	1,987	
 	 	1,479	
 	 	91	
 	 	(94	)	 	3,463	
 	
Loss on sale of assets	—	
 	 	262	
 	 	4	
 	 	—	
 	 	266	
 	
Operating Income/(Loss)	437	
 	 	405	
 	 	(87	)	 	—	
 	 	755	
 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	
Equity in (losses)/earnings of consolidated subsidiaries	(110	)	 	(13	)	 	485	
 	 	(362	)	 	—	
 	
Equity in earnings/(losses) of unconsolidated affiliates	2	
 	 	22	
 	 	(2	)	 	(6	)	 	16	
 	
Impairment loss on investment	—	
 	 	(8	)	 	—	
 	 	—	
 	 	(8	)	
Other income	1	
 	 	8	
 	 	—	
 	 	—	
 	 	9	
 	
Loss on debt extinguishment	—	
 	 	—	
 	 	(50	)	 	—	
 	 	(50	)	
Interest expense	(4	)	 	(148	)	 	(128	)	 	—	
 	 	(280	)	
Total other (expense)/income	(111	)	 	(139	)	 	305	
 	 	(368	)	 	(313	)	
Income Before Income Taxes	326	
 	 	266	
 	 	218	
 	 	(368	)	 	442	
 	
Income tax expense/(benefit)	134	
 	 	90	
 	 	(218	)	 	43	
 	 	49	
 	
Net Income	192	
 	 	176	
 	 	436	
 	 	(411	)	 	393	
 	
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests	—	
 	 	6	
 	 	34	
 	 	(49	)	 	(9	)	
Net Income Attributable to
NRG Energy, Inc.	$	192	
 	 	$	170	
 	 	$	402	
 	 	$	(362	)	 	$	402	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

48

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2016 
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	6,079	
 	 	$	3,907	
 	 	$	—	
 	 	$	(167	)	 	$	9,819	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	4,278	
 	 	2,602	
 	 	29	
 	 	(171	)	 	6,738	
 	
Depreciation and amortization	372	
 	 	588	
 	 	19	
 	 	—	
 	 	979	
 	
Impairment losses	8	
 	 	115	
 	 	—	
 	 	—	
 	 	123	
 	
Selling, general and administrative	306	
 	 	296	
 	 	200	
 	 	—	
 	 	802	
 	
Acquisition-related transaction and integration costs	—	
 	 	1	
 	 	6	
 	 	—	
 	 	7	
 	
Development activity expenses	—	
 	 	44	
 	 	23	
 	 	—	
 	 	67	
 	
Total operating costs and expenses	4,964	
 	 	3,646	
 	 	277	
 	 	(171	)	 	8,716	
 	
Gain/(loss) on sale of assets	—	
 	 	294	
 	 	(79	)	 	—	
 	 	215	
 	
Operating Income/(Loss)	1,115	
 	 	555	
 	 	(356	)	 	4	
 	 	1,318	
 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	
Equity in (losses)/earnings of consolidated subsidiaries	(178	)	 	(36	)	 	796	
 	 	(582	)	 	—	
 	
Equity in earnings/(losses) of unconsolidated affiliates	5	
 	 	20	
 	 	(2	)	 	(10	)	 	13	
 	
Impairment loss on investment	—	
 	 	(147	)	 	—	
 	 	—	
 	 	(147	)	
Other income	3	
 	 	31	
 	 	2	
 	 	(1	)	 	35	
 	
Loss on debt extinguishment	—	
 	 	(4	)	 	(115	)	 	—	
 	 	(119	)	
Interest expense	(11	)	 	(443	)	 	(387	)	 	—	
 	 	(841	)	
Total other (expense)/income	(181	)	 	(579	)	 	294	
 	 	(593	)	 	(1,059	)	
Income/(Loss) Before Income Taxes	934	
 	 	(24	)	 	(62	)	 	(589	)	 	259	
 	
Income tax expense/(benefit)	367	
 	 	(22	)	 	(345	)	 	95	
 	 	95	
 	
Net Income	567	
 	 	(2	)	 	283	
 	 	(684	)	 	164	
 	
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—	
 	 	(17	)	 	70	
 	 	(102	)	 	(49	)	
Net Income Attributable to
NRG Energy, Inc.	$	567	
 	 	$	15	
 	 	$	213	
 	 	$	(582	)	 	$	213	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

49

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Three Months Ended September 30, 2016 
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Net Income	$	192	
 	 	$	176	
 	 	$	436	
 	 	$	(411	)	 	$	393	
 	
Other Comprehensive Income/(Loss), net of tax	 	 	 	 	 	 	 	 	 	
Unrealized gain on derivatives, net	—	
 	 	40	
 	 	26	
 	 	(39	)	 	27	
 	
Foreign currency translation adjustments, net	2	
 	 	2	
 	 	4	
 	 	(5	)	 	3	
 	
Available-for-sale securities, net	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	
Defined benefit plans, net	54	
 	 	—	
 	 	(23	)	 	—	
 	 	31	
 	
Other comprehensive income	56	
 	 	42	
 	 	7	
 	 	(44	)	 	61	
 	
Comprehensive Income	248	
 	 	218	
 	 	443	
 	 	(455	)	 	454	
 	
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—	
 	 	13	
 	 	34	
 	 	(49	)	 	(2	)	
Comprehensive Income Attributable to NRG Energy, Inc.	248	
 	 	205	
 	 	409	
 	 	(406	)	 	456	
 	
Comprehensive Income Available for Common Stockholders	$	248	
 	 	$	205	
 	 	$	409	
 	 	$	(406	)	 	$	456	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

50

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Nine Months Ended September 30, 2016 
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Net Income/(Loss)	$	567	
 	 	$	(2	)	 	$	283	
 	 	$	(684	)	 	$	164	
 	
Other Comprehensive Income/(Loss), net of tax	 	 	 	 	 	 	 	 	 	
Unrealized (loss)/gain on derivatives, net	—	
 	 	(15	)	 	46	
 	 	(39	)	 	(8	)	
Foreign currency translation adjustments, net	4	
 	 	4	
 	 	6	
 	 	(8	)	 	6	
 	
Available-for-sale securities, net	—	
 	 	—	
 	 	1	
 	 	—	
 	 	1	
 	
Defined benefit plans, net	55	
 	 	—	
 	 	(23	)	 	—	
 	 	32	
 	
Other comprehensive income/(loss)	59	
 	 	(11	)	 	30	
 	 	(47	)	 	31	
 	
Comprehensive Income/(Loss)	626	
 	 	(13	)	 	313	
 	 	(731	)	 	195	
 	
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—	
 	 	(38	)	 	70	
 	 	(102	)	 	(70	)	
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	626	
 	 	25	
 	 	243	
 	 	(629	)	 	265	
 	
Gain on redemption, net of dividends for preferred shares	—	
 	 	—	
 	 	(73	)	 	—	
 	 	(73	)	
Comprehensive Income/(Loss) Available for Common Stockholders	$	626	
 	 	$	25	
 	 	$	316	
 	 	$	(629	)	 	$	338	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

51

52

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
September 30, 2016 
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
ASSETS	(In millions)	
Current Assets	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	$	—	
 	 	$	1,744	
 	 	$	691	
 	 	$	—	
 	 	$	2,435	
 	
Funds deposited by counterparties	6	
 	 	10	
 	 	—	
 	 	—	
 	 	16	
 	
Restricted cash	10	
 	 	470	
 	 	—	
 	 	—	
 	 	480	
 	
Accounts receivable - trade, net	880	
 	 	482	
 	 	—	
 	 	—	
 	 	1,362	
 	
Accounts receivable - affiliate	308	
 	 	(133	)	 	173	
 	 	(343	)	 	5	
 	
Inventory	425	
 	 	592	
 	 	—	
 	 	—	
 	 	1,017	
 	
Derivative instruments	700	
 	 	384	
 	 	—	
 	 	(120	)	 	964	
 	
Cash collateral paid in support of energy risk management activities	206	
 	 	131	
 	 	—	
 	 	—	
 	 	337	
 	
Renewable energy grant receivable, net	—	
 	 	34	
 	 	—	
 	 	—	
 	 	34	
 	
Prepayments and other current assets	70	
 	 	237	
 	 	57	
 	 	—	
 	 	364	
 	
Total current assets	2,605	
 	 	3,951	
 	 	921	
 	
 	(463	)	 	7,014	
 	
Net property, plant and equipment	4,310	
 	 	13,667	
 	 	253	
 	 	(27	)	 	18,203	
 	
Other Assets	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	875	
 	 	2,054	
 	 	10,781	
 	 	(13,710	)	 	—	
 	
Equity investments in affiliates	(14	)	 	906	
 	 	8	
 	 	—	
 	 	900	
 	
Notes receivable, less current portion	—	
 	 	21	
 	 	—	
 	 	—	
 	 	21	
 	
Goodwill	697	
 	 	302	
 	 	—	
 	 	—	
 	 	999	
 	
Intangible assets, net	651	
 	 	1,457	
 	 	1	
 	 	(3	)	 	2,106	
 	
Nuclear decommissioning trust fund	605	
 	 	—	
 	 	—	
 	 	—	
 	 	605	
 	
Derivative instruments	231	
 	 	80	
 	 	6	
 	 	(61	)	 	256	
 	
Deferred income tax	—	
 	 	182	
 	 	7	
 	 	—	
 	 	189	
 	
Other non-current assets	43	
 	 	814	
 	 	341	
 	 	—	
 	 	1,198	
 	
Total other assets	3,088	
 	 	5,816	
 	 	11,144	
 	 	(13,774	)	 	6,274	
 	
Total Assets	$	10,003	
 	 	$	23,434	
 	 	$	12,318	
 	 	$	(14,264	)	 	$	31,491	
 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	$	—	
 	 	$	1,475	
 	 	$	(254	)	 	$	—	
 	 	$	1,221	
 	
Accounts payable	577	
 	 	330	
 	 	38	
 	 	—	
 	 	945	
 	
Accounts payable — affiliate	128	
 	 	158	
 	 	57	
 	 	(343	)	 	—	
 	
Derivative instruments	601	
 	 	485	
 	 	3	
 	 	(120	)	 	969	
 	
Cash collateral received in support of energy risk management activities	6	
 	 	10	
 	 	—	
 	 	—	
 	 	16	
 	
Accrued expenses and other current liabilities	301	
 	 	489	
 	 	360	
 	 	—	
 	 	1,150	
 	
Total current liabilities	1,613	
 	 	2,947	
 	 	204	
 	 	(463	)	 	4,301	
 	
Other Liabilities	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	244	
 	 	10,011	
 	 	7,763	
 	 	—	
 	 	18,018	
 	
Nuclear decommissioning reserve	284	
 	 	—	
 	 	—	
 	 	—	
 	 	284	
 	
Nuclear decommissioning trust liability	309	
 	 	—	
 	 	—	
 	 	—	
 	 	309	
 	
Deferred income taxes	1,068	
 	 	(112	)	 	(909	)	 	—	
 	 	47	
 	
Derivative instruments	233	
 	 	303	
 	 	—	
 	 	(61	)	 	475	
 	
Out-of-market contracts, net	84	
 	 	981	
 	 	—	
 	 	—	
 	 	1,065	
 	
Other non-current liabilities	361	
 	 	787	
 	 	332	
 	 	—	
 	 	1,480	
 	
Total non-current liabilities	2,583	
 	 	11,970	
 	 	7,186	
 	 	(61	)	 	21,678	
 	
Total liabilities	4,196	
 	 	14,917	
 	 	7,390	
 	 	(524	)	 	25,979	
 	
Redeemable noncontrolling interest in subsidiaries	—	
 	 	19	
 	 	—	
 	 	—	
 	 	19	
 	
Stockholders’ Equity	5,807	
 	 	8,498	
 	 	4,928	
 	 	(13,740	)	 	5,493	
 	
Total Liabilities and Stockholders’ Equity	$	10,003	
 	 	$	23,434	
 	 	$	12,318	
 	 	$	(14,264	)	 	$	31,491	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

53

NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2016 (Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	
Net Income	$	567	
 	 	$	(2	)	 	$	283	
 	 	$	(684	)	 	$	164	
 	
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
 	
Distributions from unconsolidated affiliates	—	
 	 	65	
 	 	—	
 	 	(8	)	 	57	
 	
Equity in (earnings)/losses of unconsolidated affiliates	(5	)	 	(20	)	 	2	
 	 	10	
 	 	(13	)	
Depreciation and amortization	372	
 	 	588	
 	 	19	
 	 	—	
 	 	979	
 	
Provision for bad debts	31	
 	 	5	
 	 	—	
 	 	—	
 	 	36	
 	
Amortization of nuclear fuel	39	
 	 	—	
 	 	—	
 	 	—	
 	 	39	
 	
Amortization of financing costs and debt discount/premiums	—	
 	 	(14	)	 	17	
 	 	—	
 	 	3	
 	
Adjustment for debt extinguishment	—	
 	 	4	
 	 	17	
 	 	—	
 	 	21	
 	
Amortization of intangibles and out-of-market contracts	32	
 	 	41	
 	 	—	
 	 	—	
 	 	73	
 	
Amortization of unearned equity compensation	—	
 	 	—	
 	 	23	
 	 	—	
 	 	23	
 	
Impairment losses	8	
 	 	262	
 	 	—	
 	 	—	
 	 	270	
 	
Changes in deferred income taxes and liability for uncertain tax benefits	(134	)	 	(90	)	 	253	
 	 	—	
 	 	29	
 	
Changes in nuclear decommissioning trust liability	24	
 	 	—	
 	 	—	
 	 	—	
 	 	24	
 	
Changes in derivative instruments	(173	)	 	258	
 	 	(3	)	 	—	
 	 	82	
 	
Changes in collateral deposits supporting energy risk management activities	268	
 	 	(37	)	 	—	
 	 	—	
 	 	231	
 	
Proceeds from sale of emission allowances	47	
 	 	—	
 	 	—	
 	 	—	
 	 	47	
 	
(Gain)/loss on sale of assets	—	
 	 	(294	)	 	70	
 	 	
 	 	(224	)	
Cash (used)/provided by changes in other working capital	(887	)	 	305	
 	 	(208	)	 	682	
 	 	(108	)	
Net Cash Provided by Operating Activities	189	
 	 	1,071	
 	 	473	
 	 	—	
 	 	1,733	
 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	
 	
Dividends from NRG Yield, Inc.	—	
 	 	—	
 	 	59	
 	 	(59	)	 	—	
 	
Acquisition of September 2016 Drop Down Assets, net of cash acquired	—	
 	 	(77	)	 	—	
 	 	77	
 	 	—	
 	
Intercompany dividends	—	
 	 	—	
 	 	12	
 	 	(12	)	 	—	
 	
Acquisition of businesses, net of cash acquired	—	
 	 	(18	)	 	—	
 	 	—	
 	 	(18	)	
Capital expenditures	(145	)	 	(713	)	 	(40	)	 	—	
 	 	(898	)	
Increase in restricted cash, net	(5	)	 	(25	)	 	—	
 	 	—	
 	 	(30	)	
Increase in restricted cash — U.S. DOE funded projects	—	
 	 	(36	)	 	—	
 	 	—	
 	 	(36	)	
Decrease in notes receivable	—	
 	 	2	
 	 	—	
 	 	—	
 	 	2	
 	
Purchases of emission allowances	(32	)	 	—	
 	 	—	
 	 	—	
 	 	(32	)	
Proceeds from sale of emission allowances	47	
 	 	—	
 	 	—	
 	 	—	
 	 	47	
 	
Investments in nuclear decommissioning trust fund securities	(378	)	 	—	
 	 	—	
 	 	—	
 	 	(378	)	
Proceeds from sales of nuclear decommissioning trust fund securities	354	
 	 	—	
 	 	—	
 	 	—	
 	 	354	
 	
Proceeds from renewable energy grants and state rebates	—	
 	 	11	
 	 	—	
 	 	—	
 	 	11	
 	
Proceeds from sale of assets, net of cash disposed of	—	
 	 	619	
 	 	17	
 	 	—	
 	 	636	
 	
Proceeds from (investments in) unconsolidated affiliates	2	
 	 	(25	)	 	—	
 	 	—	
 	 	(23	)	
Other	27	
 	 	9	
 	 	8	
 	 	—	
 	 	44	
 	
Net Cash (Used)/Provided by Investing Activities	(130	)	 	(253	)	 	56	
 	 	6	
 	 	(321	)	
Cash Flows from Financing Activities	

 	 	 	
 	 	 	 	 	
Dividends from NRG Yield, Inc.	—	
 	 	(59	)	 	—	
 	 	59	
 	 	—	
 	
Payments (for)/from intercompany loans	(2	)	 	(134	)	 	136	
 	 	—	
 	 	—	
 	
Acquisition of September 2016 Drop Down Assets, net of cash acquired	—	
 	 	—	
 	 	77	
 	 	(77	)	 	—	
 	
Intercompany dividends	(52	)	 	40	
 	 	—	
 	 	12	
 	 	—	
 	
Payment of dividends to common and preferred stockholders	—	
 	 	—	
 	 	(66	)	 	—	
 	 	(66	)	
Payment for preferred shares	—	
 	 	—	
 	 	(226	)	 	—	
 	 	(226	)	
Net receipts from settlement of acquired derivatives that include financing elements	—	
 	 	129	
 	 	—	
 	 	—	
 	 	129	
 	
Proceeds from issuance of long-term debt	—	
 	 	1,097	
 	 	4,140	
 	 	—	
 	 	5,237	
 	
Payments for short and long-term debt	(2	)	 	(815	)	 	(4,540	)	 	—	
 	 	(5,357	)	
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—	
 	 	(127	)	 	—	
 	 	—	
 	 	(127	)	
Proceeds from issuance of common stock	—	
 	 	—	
 	 	1	
 	 	—	
 	 	1	
 	
Payment of debt issuance costs	—	
 	 	(17	)	 	(53	)	 	—	
 	 	(70	)	
Other - contingent consideration	(3	)	 	(7	)	 	—	
 	 	—	
 	 	(10	)	
Net Cash (Used)/Provided by Financing Activities	(59	)	 	107	
 	 	(531	)	 	(6	)	 	(489	)	
Effect of exchange rate changes on cash and cash equivalents	—	
 	 	(6	)	 	—	
 	 	—	
 	 	(6	)	
Net Increase/(Decrease) in Cash and Cash Equivalents	—	
 	 	919	
 	 	(2	)	 	—	
 	 	917	
 	
Cash and Cash Equivalents at Beginning of Period	—	
 	 	825	
 	 	693	
 	 	—	
 	 	1,518	
 	
Cash and Cash Equivalents at End of Period	$	—	
 	
 	$	1,744	
 	
 	$	691	
 	
 	$	—	
 	 	$	2,435	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

54

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended September 30, 2015  
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	3,132	
 	 	$	1,331	
 	 	$	—	
 	 	$	(29	)	 	$	4,434	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	2,276	
 	 	792	
 	 	14	
 	 	(40	)	 	3,042	
 	
Depreciation and amortization	190	
 	 	187	
 	 	5	
 	 	—	
 	 	382	
 	
Selling, general and administrative	136	
 	 	91	
 	 	100	
 	 	—	
 	 	327	
 	
Impairment losses	222	
 	 	41	
 	 	—	
 	 	—	
 	 	263	
 	
Acquisition-related transaction and integration costs	—	
 	 	2	
 	 	1	
 	 	—	
 	 	3	
 	
Development activity expenses	—	
 	 	17	
 	 	21	
 	 	—	
 	 	38	
 	
Total operating costs and expenses	2,824	
 	 	1,130	
 	 	141	
 	 	(40	)	 	4,055	
 	
Operating Income/(Loss)	308	
 	 	201	
 	 	(141	)	 	11	
 	 	379	
 	
Other Income/(Expense)	 	 	 	 	 	
 	 	 	 	 	
Equity in earnings of consolidated subsidiaries	—	
 	 	42	
 	 	228	
 	 	(270	)	 	—	
 	
Equity in earnings of unconsolidated affiliates	3	
 	 	27	
 	 	1	
 	 	(7	)	 	24	
 	
Other income, net	2	
 	 	3	
 	 	1	
 	 	(2	)	 	4	
 	
Loss on debt extinguishment	—	
 	 	(2	)	 	—	
 	 	—	
 	 	(2	)	
Interest expense	(4	)	 	(151	)	 	(136	)	 	—	
 	 	(291	)	
Total other income/(expense)	1	
 	 	(81	)	 	94	
 	 	(279	)	 	(265	)	
Income/(Loss) Before Income Taxes	309	
 	 	120	
 	 	(47	)	 	(268	)	 	114	
 	
Income tax expense/(benefit)	88	
 	 	56	
 	 	(130	)	 	33	
 	 	47	
 	
Net Income	221	
 	 	64	
 	 	83	
 	 	(301	)	 	67	
 	
Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest	—	
 	 	15	
 	 	17	
 	 	(31	)	 	1	
 	
Net Income Attributable to NRG Energy, Inc.	$	221	
 	 	$	49	
 	 	$	66	
 	 	$	(270	)	 	$	66	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

55

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2015  
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	$	7,959	
 	 	$	3,801	
 	 	$	—	
 	 	$	(97	)	 	$	11,663	
 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	6,083	
 	 	2,554	
 	 	10	
 	 	(96	)	 	8,551	
 	
Depreciation and amortization	590	
 	 	568	
 	 	15	
 	 	—	
 	 	1,173	
 	
Selling, general and administrative	351	
 	 	280	
 	 	247	
 	 	—	
 	 	878	
 	
Impairment losses	222	
 	 	41	
 	 	—	
 	 	—	
 	 	263	
 	
Acquisition-related transaction and integration costs	—	
 	 	3	
 	 	13	
 	 	—	
 	 	16	
 	
Development activity expenses	—	
 	 	43	
 	 	66	
 	 	—	
 	 	109	
 	
Total operating costs and expenses	7,246	
 	 	3,489	
 	 	351	
 	 	(96	)	 	10,990	
 	
Gain on postretirement benefits curtailment	—	
 	 	14	
 	 	—	
 	 	—	
 	 	14	
 	
Operating Income/(Loss)	713	
 	 	326	
 	 	(351	)	 	(1	)	 	687	
 	
Other Income/(Expense)	 	 	 	 	 	
 	 	 	 	 	
Equity in (losses)/earnings of consolidated subsidiaries	(35	)	 	(15	)	 	432	
 	 	(382	)	 	—	
 	
Equity in earnings of unconsolidated affiliates	6	
 	 	33	
 	 	—	
 	 	(10	)	 	29	
 	
Other income, net	3	
 	 	23	
 	 	3	
 	 	(2	)	 	27	
 	
Loss on debt extinguishment	—	
 	 	(9	)	 	—	
 	 	—	
 	 	(9	)	
Interest expense	(13	)	 	(430	)	 	(412	)	 	—	
 	 	(855	)	
Total other (expense)/income	(39	)	 	(398	)	 	23	
 	 	(394	)	 	(808	)	
Income/(Loss) Before Income Taxes	674	
 	 	(72	)	 	(328	)	 	(395	)	 	(121	)	
Income tax expense/(benefit)	225	
 	 	(20	)	 	(281	)	 	33	
 	 	(43	)	
Net Income/(Loss)	449	
 	 	(52	)	 	(47	)	 	(428	)	 	(78	)	
Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest	—	
 	 	15	
 	 	21	
 	 	(46	)	 	(10	)	
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	449	
 	 	$	(67	)	 	$	(68	)	 	$	(382	)	 	$	(68	)	
 	 	
(a)	All significant intercompany transactions have been eliminated in consolidation.	

56

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Three Months Ended September 30, 2015  
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Net Income	$	221	
 	 	$	64	
 	 	$	83	
 	 	$	(301	)	 	$	67	
 	
Other Comprehensive Income/(Loss), net of tax	 	 	 	 	 	 	 	 	 	
Unrealized (loss)/gain on derivatives, net	(5	)	 	(24	)	 	20	
 	 	3	
 	 	(6	)	
Foreign currency translation adjustments, net	—	
 	 	(6	)	 	(2	)	 	—	
 	 	(8	)	
Available-for-sale securities, net	—	
 	 	12	
 	 	(19	)	 	—	
 	 	(7	)	
Defined benefit plans, net	4	
 	 	(1	)	 	—	
 	 	—	
 	 	3	
 	
Other comprehensive loss	(1	)	 	(19	)	 	(1	)	 	3	
 	 	(18	)	
Comprehensive Income	220	
 	 	45	
 	 	82	
 	 	(298	)	 	49	
 	
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—	
 	 	(3	)	 	17	
 	 	(31	)	 	(17	)	
Comprehensive Income Attributable to NRG Energy, Inc.	220	
 	 	48	
 	 	65	
 	 	(267	)	 	66	
 	
Dividends for preferred shares	—	
 	 	—	
 	 	5	
 	 	—	
 	 	5	
 	
Comprehensive Income Available for Common Stockholders	$	220	
 	 	$	48	
 	 	$	60	
 	 	$	(267	)	 	$	61	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

57

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Nine Months Ended September 30, 2015  
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Net Income/(Loss)	$	449	
 	 	$	(52	)	 	$	(47	)	 	$	(428	)	 	$	(78	)	
Other Comprehensive Income/(Loss), net of tax	 	 	 	 	 	 	 	 	 	
Unrealized (loss)/gain on derivatives, net	(10	)	 	(9	)	 	29	
 	 	(12	)	 	(2	)	
Foreign currency translation adjustments, net	—	
 	 	(6	)	 	(4	)	 	—	
 	 	(10	)	
Available-for-sale securities, net	—	
 	 	11	
 	 	(22	)	 	—	
 	 	(11	)	
Defined benefit plans, net	1	
 	 	(2	)	 	10	
 	 	—	
 	 	9	
 	
Other comprehensive (loss)/income	(9	)	 	(6	)	 	13	
 	 	(12	)	 	(14	)	
Comprehensive Income/(Loss)	440	
 	 	(58	)	 	(34	)	 	(440	)	 	(92	)	
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—	
 	 	(9	)	 	21	
 	 	(46	)	 	(34	)	
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	440	
 	 	(49	)	 	(55	)	 	(394	)	 	(58	)	
Dividends for preferred shares	—	
 	 	—	
 	 	15	
 	 	—	
 	 	15	
 	
Comprehensive Income/(Loss) Available for Common Stockholders	$	440	
 	 	$	(49	)	 	$	(70	)	 	$	(394	)	 	$	(73	)	
 	 	
(a)	All significant intercompany transactions have been eliminated in consolidation.	

58

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2015 

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations (a)	 	Consolidated	
ASSETS	(In millions)	
Current Assets	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	$	—	
 	 	$	825	
 	 	$	693	
 	 	$	—	
 	 	$	1,518	
 	
Funds deposited by counterparties	55	
 	 	51	
 	 	—	
 	 	—	
 	 	106	
 	
Restricted cash	5	
 	 	409	
 	 	—	
 	 	—	
 	 	414	
 	
Accounts receivable - trade, net	851	
 	 	304	
 	 	2	
 	 	—	
 	 	1,157	
 	
Accounts receivable - affiliate	395	
 	 	260	
 	 	571	
 	 	(1,222	)	 	4	
 	
Inventory	570	
 	 	682	
 	 	—	
 	 	—	
 	 	1,252	
 	
Derivative instruments	1,202	
 	 	871	
 	 	—	
 	 	(158	)	 	1,915	
 	
Cash collateral paid in support of energy risk management activities	474	
 	 	94	
 	 	—	
 	 	—	
 	 	568	
 	
Renewable energy grant receivable, net	—	
 	 	13	
 	 	—	
 	 	—	
 	 	13	
 	
Current assets held-for-sale	—	
 	 	6	
 	 	—	
 	 	—	
 	 	6	
 	
Prepayments and other current assets	93	
 	 	274	
 	 	71	
 	 	—	
 	 	438	
 	
Total current assets	3,645	
 	 	3,789	
 	 	1,337	
 	 	(1,380	)	 	7,391	
 	
Net Property, Plant and Equipment	4,767	
 	 	13,773	
 	 	219	
 	 	(27	)	 	18,732	
 	
Other Assets	 	 	 	 	 	 	 	 	 	
Investment in subsidiaries	842	
 	 	2,244	
 	 	11,039	
 	 	(14,125	)	 	—	
 	
Equity investments in affiliates	(14	)	 	1,160	
 	 	1	
 	 	(102	)	 	1,045	
 	
Notes receivable, less current portion	—	
 	 	46	
 	 	7	
 	 	—	
 	 	53	
 	
Goodwill	697	
 	 	302	
 	 	—	
 	 	—	
 	 	999	
 	
Intangible assets, net	763	
 	 	1,551	
 	 	2	
 	 	(6	)	 	2,310	
 	
Nuclear decommissioning trust fund	561	
 	 	—	
 	 	—	
 	 	—	
 	 	561	
 	
Derivative instruments	153	
 	 	184	
 	 	—	
 	 	(32	)	 	305	
 	
Deferred income taxes	(6	)	 	815	
 	 	(642	)	 	—	
 	 	167	
 	
Non-current assets held for sale	—	
 	 	105	
 	 	—	
 	 	—	
 	 	105	
 	
Other non-current assets	80	
 	 	749	
 	 	385	
 	 	—	
 	 	1,214	
 	
Total other assets	3,076	
 	 	7,156	
 	 	10,792	
 	 	(14,265	)	 	6,759	
 	
Total Assets	$	11,488	
 	 	$	24,718	
 	 	$	12,348	
 	 	$	(15,672	)	 	$	32,882	
 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	$	2	
 	 	$	460	
 	 	$	19	
 	 	$	—	
 	 	$	481	
 	
Accounts payable	553	
 	 	277	
 	 	39	
 	 	—	
 	 	869	
 	
Accounts payable — affiliate	151	
 	 	2,000	
 	 	(929	)	 	(1,222	)	 	—	
 	
Derivative instruments	1,130	
 	 	749	
 	 	—	
 	 	(158	)	 	1,721	
 	
Cash collateral received in support of energy risk management activities	55	
 	 	51	
 	 	—	
 	 	—	
 	 	106	
 	
Current liabilities held-for-sale	—	
 	 	2	
 	 	—	
 	 	—	
 	 	2	
 	
Accrued expenses and other current liabilities	319	
 	 	429	
 	 	449	
 	 	(1	)	 	1,196	
 	
Total current liabilities	2,210	
 	 	3,968	
 	 	(422	)	 	(1,381	)	 	4,375	
 	
Other Liabilities	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	302	
 	 	10,496	
 	 	8,185	
 	 	—	
 	 	18,983	
 	
Nuclear decommissioning reserve	326	
 	 	—	
 	 	—	
 	 	—	
 	 	326	
 	
Nuclear decommissioning trust liability	283	
 	 	—	
 	 	—	
 	 	—	
 	 	283	
 	
Deferred income taxes	179	
 	 	(1,088	)	 	928	
 	 	—	
 	 	19	
 	
Derivative instruments	301	
 	 	224	
 	 	—	
 	 	(32	)	 	493	
 	
Out-of-market contracts, net	95	
 	 	1,051	
 	 	—	
 	 	—	
 	 	1,146	
 	
Non-current liabilities held-for-sale	—	
 	 	4	
 	 	—	
 	 	—	
 	 	4	
 	
Other non-current liabilities	554	
 	 	735	
 	 	199	
 	 	—	
 	 	1,488	
 	
Total non-current liabilities	2,040	
 	 	11,422	
 	 	9,312	
 	 	(32	)	 	22,742	
 	
Total Liabilities	4,250	
 	 	15,390	
 	 	8,890	
 	 	(1,413	)	 	27,117	
 	
2.822% Preferred Stock	—	
 	 	—	
 	 	302	
 	 	—	
 	 	302	
 	
Redeemable noncontrolling interest in subsidiaries	—	
 	 	29	
 	 	—	
 	 	—	
 	 	29	
 	
Stockholders’ Equity	7,238	
 	 	9,299	
 	 	3,156	
 	 	(14,259	)	 	5,434	
 	
Total Liabilities and Stockholders’ Equity	$	11,488	
 	 	$	24,718	
 	 	$	12,348	
 	 	$	(15,672	)	 	$	32,882	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

59

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2015  
(Unaudited)

 	Guarantor Subsidiaries	 	Non-Guarantor Subsidiaries	 	NRG Energy, Inc.
(Note Issuer)	 	Eliminations(a)	 	Consolidated	
 	(In millions)	
Cash Flows from Operating Activities	 	 	 	 	 	 	 	 	 	
Net Income/(Loss)	$	449	
 	 	$	(52	)	 	$	(47	)	 	$	(428	)	 	$	(78	)	
Adjustments to reconcile net loss to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	
Distributions from unconsolidated affiliates	—	
 	 	77	
 	 	—	
 	 	(20	)	 	57	
 	
Equity in earnings of unconsolidated affiliates	(6	)	 	(33	)	 	—	
 	 	10	
 	 	(29	)	
Depreciation and amortization	590	
 	 	568	
 	 	15	
 	 	—	
 	 	1,173	
 	
Provision for bad debts	46	
 	 	—	
 	 	3	
 	 	—	
 	 	49	
 	
Amortization of nuclear fuel	36	
 	 	—	
 	 	—	
 	 	—	
 	 	36	
 	
Amortization of financing costs and debt discount/premiums	—	
 	 	(29	)	 	20	
 	 	
 	 	(9	)	
Adjustment for debt extinguishment	—	
 	 	9	
 	 	—	
 	 	—	
 	 	9	
 	
Amortization of intangibles and out-of-market contracts	43	
 	 	25	
 	 	—	
 	 	—	
 	 	68	
 	
Amortization of unearned equity compensation	—	
 	 	—	
 	 	37	
 	 	—	
 	 	37	
 	
Changes in deferred income taxes and liability for uncertain tax benefits	218	
 	 	(77	)	 	(213	)	 	—	
 	 	(72	)	
Changes in nuclear decommissioning trust liability	1	
 	 	—	
 	 	—	
 	 	—	
 	 	1	
 	
Changes in derivative instruments	135	
 	 	89	
 	 	(44	)	 	—	
 	 	180	
 	
Changes in collateral deposits supporting energy risk management activities	(141	)	 	(39	)	 	—	
 	 	—	
 	 	(180	)	
Gain on sale of emission allowances	(6	)	 	—	
 	 	—	
 	 	—	
 	 	(6	)	
Gain on postretirement benefits curtailment	—	
 	 	(14	)	 	—	
 	 	—	
 	 	(14	)	
Impairment losses	222	
 	 	41	
 	 	—	
 	 	—	
 	 	263	
 	
Cash provided/(used) by changes in other working capital	1,048	
 	 	(879	)	 	(702	)	 	440	
 	 	(93	)	
Net Cash Provided/(Used) by Operating Activities	2,635	
 	 	(314	)	
 	(931	)	
 	2	
 	 	1,392	
 	
Cash Flows from Investing Activities	 	 	 	 	 	 	 	 	 	
Acquisition of January 2015 Drop Down Assets, net of cash acquired	—	
 	 	(489	)	 	—	
 	 	489	
 	 	—	
 	
Dividends from NRG Yield, Inc.	—	
 	 	—	
 	 	52	
 	 	(52	)	 	—	
 	
Intercompany dividends	—	
 	 	—	
 	 	33	
 	 	(33	)	 	—	
 	
Acquisition of businesses, net of cash acquired	—	
 	 	(31	)	 	—	
 	 	—	
 	 	(31	)	
Capital expenditures	(264	)	 	(595	)	 	(30	)	 	—	
 	 	(889	)	
Increase in restricted cash, net	(3	)	 	(38	)	 	—	
 	 	—	
 	 	(41	)	
Decrease in restricted cash — U.S. DOE projects	—	
 	 	1	
 	 	—	
 	 	—	
 	 	1	
 	
Decrease in notes receivable	—	
 	 	10	
 	 	—	
 	 	—	
 	 	10	
 	
Purchases of emission allowances	(40	)	 	—	
 	 	—	
 	 	—	
 	 	(40	)	
Proceeds from sale of emission allowances	45	
 	 	—	
 	 	—	
 	 	—	
 	 	45	
 	
Investments in nuclear decommissioning trust fund securities	(500	)	 	—	
 	 	—	
 	 	—	
 	 	(500	)	
Proceeds from sales of nuclear decommissioning trust fund securities	499	
 	 	—	
 	 	—	
 	 	—	
 	 	499	
 	
Proceeds from renewable energy grants and state rebates	—	
 	 	62	
 	 	—	
 	 	—	
 	 	62	
 	
Proceeds from sale of assets, net of cash disposed of	—	
 	 	—	
 	 	1	
 	 	—	
 	 	1	
 	
Investments in unconsolidated affiliates	1	
 	 	(317	)	 	(39	)	 	(2	)	 	(357	)	
Other	—	
 	 	8	
 	 	—	
 	 	—	
 	 	8	
 	
Net Cash Used by Investing Activities	(262	)	 	(1,389	)	 	17	
 	 	402	
 	 	(1,232	)	
Cash Flows from Financing Activities	 	 	 	 	 	 	 	 	 	
Proceeds from intercompany loans to subsidiaries	(2,391	)	 	1,178	
 	 	1,213	
 	 	—	
 	 	—	
 	
Acquisition of January 2015 Drop Down Assets, net of cash acquired	—	
 	 	—	
 	 	489	
 	 	(489	)	 	—	
 	
Intercompany dividends	—	
 	 	(33	)	 	—	
 	 	33	
 	 	—	
 	
Payments of dividends from NRG Yield, Inc.	—	
 	 	(52	)	 	—	
 	 	52	
 	 	—	
 	
Payment of dividends to common and preferred stockholders	—	
 	 	—	
 	 	(152	)	 	—	
 	 	(152	)	
Payment for treasury stock	—	
 	 	—	
 	 	(353	)	 	—	
 	 	(353	)	
Net receipts for settlement of acquired derivatives that include financing elements	—	
 	 	138	
 	 	—	
 	 	—	
 	 	138	
 	
Proceeds from issuance of long-term debt	—	
 	 	635	
 	 	44	
 	 	—	
 	 	679	
 	
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—	
 	 	651	
 	 	—	
 	 	—	
 	 	651	
 	
Proceeds from issuance of common stock	—	
 	 	—	
 	 	1	
 	 	—	
 	 	1	
 	
Payment of debt issuance costs	—	
 	 	(14	)	 	—	
 	 	—	
 	 	(14	)	
Payments for short and long-term debt	—	
 	 	(938	)	 	(16	)	 	—	
 	 	(954	)	
Other	—	
 	 	(22	)	 	—	
 	 	—	
 	 	(22	)	
Net Cash Provided by Financing Activities	(2,391	)	 	1,543	
 	 	1,226	
 	 	(404	)	 	(26	)	
Effect of exchange rate changes on cash and cash equivalents	—	
 	 	15	
 	 	—	
 	 	—	
 	 	15	
 	
Net (Decrease)/Increase in Cash and Cash Equivalents	(18	)	 	(145	)	 	312	
 	 	—	
 	 	149	
 	
Cash and Cash Equivalents at Beginning of Period	18	
 	 	1,455	
 	 	643	
 	 	—	
 	 	2,116	
 	
Cash and Cash Equivalents at End of Period	$	—	
 	 	$	1,310	
 	 	$	955	
 	 	$	—	
 	 	$	2,265	

(a)	All significant intercompany transactions have been eliminated in consolidation.	

60

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2016 and 2015. Also refer to NRG's 2015 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.
The discussion and analysis below has been organized as follows:
 	 	
•	Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;	
 	 	
•	Results of operations;	
 	 	
•	Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements, commitments, and off-balance sheet arrangements; and	
 	 	
•	Known trends that may affect NRG's results of operations and financial condition in the future.	

61

Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is an integrated competitive power company that aims to create a sustainable energy future by producing, selling and delivering energy and energy products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG has one of the nation's largest and most diverse competitive generation portfolios balanced with a leading retail electricity platform. The Company owns and operates approximately 46,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.
The following table summarizes NRG's global generation portfolio as of September 30, 2016, by operating segment:

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Global Generation Portfolio(a) 	 	
 	 	(In MW)	 	
 	 	Generation	 	 	 	 	 	 	 	 	
Generation Type	 	Gulf Coast	 	East	 	West	 	International	 	Renewables(b)	 	NRG Yield  (c)	 	Other (d)	 	Total Global	
Natural gas(e)	 	8,651	
 	 	7,847	
 	 	6,085	
 	 	144	
 	 	—	
 	 	1,878	
 	 	—	
 	 	24,605	
 	
Coal(f)	 	5,114	
 	 	7,465	
 	 	—	
 	 	605	
 	 	—	
 	 	—	
 	 	—	
 	 	13,184	
 	
Oil(g)	 	—	
 	 	5,477	
 	 	—	
 	 	—	
 	 	—	
 	 	190	
 	 	—	
 	 	5,667	
 	
Nuclear	 	1,176	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,176	
 	
Wind	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	961	
 	 	2,005	
 	 	—	
 	 	2,966	
 	
Utility Scale Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	722	
 	 	610	
 	 	—	
 	 	1,332	
 	
Distributed Solar	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	85	
 	 	9	
 	 	114	
 	 	208	
 	
Total generation capacity	 	14,941	
 	 	20,789	
 	 	6,085	
 	 	749	
 	 	1,768	
 	 	4,692	
 	 	114	
 	 	49,138	
 	
Capacity attributable to noncontrolling interest	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(638	)	 	(2,110	)	 	—	
 	 	(2,748	)	
Total net generation capacity	 	14,941	
 	 	20,789	
 	 	6,085	
 	 	749	
 	 	1,130	
 	 	2,582	
 	 	114	
 	 	46,390	
 	
(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
(b) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2. Excludes 100 MW related to the High Lonesome Mesa facility, which was transferred to lien holders on March 31, 2016.
(c) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(d) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(e) New Castle Units 3, 4, and 5 and Joliet Units 6, 7, and 8, totaling 1,651 MW, were moved to natural gas from coal following completion of natural gas conversion projects in the second quarter of 2016. The balance of plant work is being completed for full load operation of Joliet Unit 6. Natural gas generation portfolio does not include 878 MW related to Aurora and 450 MW related to Rockford, which were both sold on July 12, 2016. Natural gas generation includes 275 MW related to Choctaw Unit 1 which is in forced outage.
(f) Coal generation portfolio does not include 94 MW related to Avon Lake 7, which retired in April 2016. New Castle Units 3, 4, and 5 and Joliet Units 6, 7, and 8, totaling 1,651 MW were moved from coal to natural gas following completion of natural gas conversion projects in the second quarter of 2016.
(g) Oil generation portfolio does not include 104 MW related to the Astoria Oil Turbines which were deactivated in the first quarter of 2016.

Strategy
NRG's strategy is to maximize stockholder value through the safe production and sale of reliable and affordable power to its customers in the markets served by the Company, while positioning the Company to meet the market's increasing demand for sustainable, low carbon and customized energy solutions for the benefit of the end-use energy consumer. This strategy is intended to enable the Company to achieve sustainable growth at reasonable margins while de-risking the Company in terms of reduced and mitigated exposure both to environmental risk and cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for its employees, customers and partners continues unabated.

62

To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) investing in, and deploying, alternative energy technologies both in its wholesale portfolio through its wind and solar portfolio and, particularly, in and around its retail businesses; and (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management; including pursuing selective acquisitions, joint ventures, divestitures and investments. The Company is currently executing several key initiatives in connection with its capital allocation plan as further described within this Management's Discussion and Analysis.
Regulatory Matters
The Company’s regulatory matters are described in the Company’s 2015 Form 10-K in Item 1, Business —  Regulatory Matters.   These matters have been updated below and in Note 15,  Regulatory Matters,  to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.
As owners of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where the Company operates.
NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.
STP License Amendment — STP Unit 1 is operating with a single-cycle license amendment issued on December 11, 2015 after a control rod was determined to be inoperable following a scheduled refueling and maintenance outage. The approved license amendment supports STP Unit 1 operation with the inoperable control rod and the associated control rod drive shaft removed. Subsequently, STPNOC submitted a permanent license amendment on May 25, 2016 to authorize continued operation of Unit 1 for the remainder of the operating license. The NRC formally accepted this submittal on June 6, 2016 and has committed to reaching a conclusion in time to support the next Unit 1 refueling outage in the spring of 2017.
East Region
PJM
2019/2020 PJM Auction Results — On May 24, 2016, PJM announced the results of its 2019/2020 base residual auction. NRG cleared approximately 11,155 MW of Capacity Performance product and 371 MW of Base Capacity product in the 2019/2020 base residual auction. NRG’s expected capacity revenues from the base residual auction for the 2019/2020 delivery year are approximately $569 million. For results of the 2018/2019 PJM base residual auction, refer to Item 1 -  Business of the 2015 Form 10-K.
The table below provides a detailed description of NRG’s 2019/2020 base residual auction results from May 24, 2016:

 	 	Base Capacity Product	 	Capacity Performance Product	
Zone	 	Cleared Capacity (MW)(1)(2)	 	Price
($/MW-day)	 	Cleared Capacity (MW)(1)(2)	 	Price
($/MW-day)	
COMED	 	65	 	$182.77	 	3,738	 	$202.77	
EMAAC	 	103	 	$99.77	 	895	 	$119.77	
MAAC	 	10	 	$80.00	 	5,972	 	$100.00	
RTO	 	193	 	$80.00	 	550	 	$100.00	
Total	 	371	 	 	 	11,155	 	 	
(1) Includes imports. Does not include capacity sold by NRG Curtailment Specialists. Excludes cleared capacity related to Aurora and Rockford, the sales of which were completed on July 12, 2016.
(2) Includes GenOn.

63

PJM Capacity Performance Appeals  — On or about July 8, 2016, four petitions were filed at the U.S. Court of Appeals for the D.C. Circuit seeking review of the FERC orders approving PJM’s Capacity Performance revisions to its forward capacity market after motions for rehearing at FERC were denied on May 10, 2016. The Company intervened in these matters on July 29, 2016. Briefing is underway. This case governs capacity revenues already received by the Company, as well as the revenues for forward periods.
AEP and FirstEnergy Ohio Contracts — On March 31, 2016, the Public Utility Commission of Ohio, or PUCO, approved  two settlements allowing AEP and FirstEnergy to recover costs associated with contracts between their regulated and un-regulated affiliates via a non-bypassable “retail rate rider” that would apply to all retail customers in Ohio.  In anticipation of the approval of the contracts, NRG, along with other companies, participated in three separate complaints at FERC, two questioning whether AEP and FirstEnergy have the regulatory approvals necessary to enter into above-market contracts with their generation affiliates without further FERC review, and one alleging that PJM’s tariff is unjust and unreasonable because it does not include provisions to prevent the artificial suppression of prices caused by state-approved out-of-market payments.  On April 27, 2016, FERC granted the complaints against AEP and FirstEnergy, and required AEP and FirstEnergy to file the Ohio PPAs with FERC for further review.  The second complaint against PJM regarding bidding rules remains pending.
In response to the FERC order granting the Company’s complaint, FirstEnergy filed both an administrative appeal at PUCO and, among other things, proposed an alternative “virtual power purchase agreement”, both of which the Company also opposed. On October 12, 2016, PUCO approved an alternative PUCO staff proposal that establishes a grid modernization fund to be paid to the FirstEnergy utilities in Ohio.  While the proposed out of market contracts would have directly impacted the PJM wholesale market, the grid modernization proposal approved by PUCO does not create an explicit subsidy for FirstEnergy’s wholesale affiliates. 

New England
Winter Reliability Program — On August 8, 2016, FERC issued an order on remand establishing a new proceeding into whether rates charged in the 2013/2014 Winter Reliability Program were just and reasonable. The Winter Reliability Program paid generators for certain costs associated with ensuring reliability during the winter period. The order on remand follows a D.C. Circuit opinion questioning whether FERC had adequately justified its acceptance of ISO-NE's proposed rates. The order directs ISO-NE to (i) collect information from each market participant on its costs of participating in the program, and (ii) directs ISO-NE to analyze whether the market results were competitive. On September 19, 2016, the Company submitted information as requested by the Internal Market Monitor and as instructed by FERC. Depending on the outcome of the proceeding, FERC could potentially direct refunds of some or all of the revenues earned by the Company.
FCM Rules for 2014 Forward Capacity Auction — On February 28, 2014, ISO-NE filed with FERC the results of Forward Capacity Auction 8. On September 16, 2014, FERC issued a notice stating that the Forward Capacity Auction 8 results would go into effect by operation of law. Several parties requested rehearing of FERC’s notice. FERC rejected those requests on legal and procedural grounds. A petition for review of FERC's decision was filed with the D.C. Circuit. The Company, along with other parties, filed a brief in support of FERC. On October 25, 2016, the D.C. Circuit rejected all challenges to the validity of the Forward Capacity Auction 8 results, finding that it had no jurisdiction to review rates allowed to go into effect by operation of law.

New York
Dunkirk Power Reliability Service and Natural Gas Addition —On February 13, 2014, Dunkirk Power LLC and National Grid agreed to a term sheet for a 10-year agreement to govern the addition of natural gas-burning capabilities to the Dunkirk facility.  This term sheet, known as the DNG Agreement Term Sheet, was approved by the NYSPSC on June 13, 2014.  On February 27, 2015, Entergy filed a complaint in the U.S. District Court for the Northern District of New York alleging that the NYSPSC’s approval of the DNG Agreement Term Sheet impermissibly interfered with FERC’s exclusive jurisdiction over the wholesale markets.  On March 7, 2016, the U.S. District Court denied a motion to dismiss filed by the NYSPSC, and litigation is ongoing.  

On May 20, 2016, the NYSPSC issued a notice soliciting comments as to whether National Grid should still be authorized to recover costs under the DNG Agreement Term Sheet given various intervening events subsequent to the Commission’s approval in 2014. The Company submitted comments on July 15, 2016 in response to the notice.

64

FERC Investigation of NYISO RMR Practices — On February 19, 2015, pursuant to Section 206 of the FPA, FERC found NYISO’s tariff to be unjust and unreasonable because it did not contain provisions governing the retention of and compensation to generating units for reliability. FERC ordered NYISO to adopt tariff provisions containing a proposed RMR rate schedule and pro forma RMR agreement. On October 19, 2015, NYISO filed its tariff revisions at FERC. NRG protested the filing. On April 21, 2016, FERC rejected in part and accepted in part NYISO’s proposed tariff provisions. Multiple parties filed for rehearing. NYISO made a compliance filing on September 19, 2016, which was protested by a generator trade association. Resolution of this matter will affect how long uneconomic resources must stay in the market before they are allowed to retire, as well as the impact units retained for reliability will have on market prices.

New York Public Service Commission Retail Energy Market Reset Order — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order.  Among other things, the Reset Order instituted a price cap on many residential and small commercial electricity and natural gas offerings.  It also required many retail providers to seek affirmative consent from select classes of retail customers over a very short period of time in order to retain those customers.  Retail suppliers who cannot meet these conditions will be required to return their customers to energy supply service provided by the local utility.  A number of interested parties both sought rehearing of the Reset Order with the NYSPSC and requested emergency judicial review.  On July 25, 2016, the New York Supreme Court vacated part of the Reset Order on procedural grounds and remanded the matter back to the NYSPSC for further consideration.  Additionally, the court order affirmed NYSPSC’s authority to regulate ESCO rates.  The matter is now on appeal before the Supreme Court of New York, Appellate Division. The outcome of this case will affect the viability of the New York retail energy market. 

New York Clean Energy Standard and Zero-Emissions Credit Nuclear Bailout — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES.  The CES order included three main components: (i) a commitment to move New York to 50% renewables by 2030; (ii) new renewable energy credit pricing for both new and existing renewable facilities; and (iii) a Zero-Emissions Credit, or ZEC, that would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. The stated purpose of the ZECs is to keep nuclear units running even though they would be uneconomic and likely retire if they received compensation only from the FERC-jurisdictional wholesale power market. The ZECs would have the effect of suppressing wholesale market prices and interfere with the wholesale market.  On October 19, 2016, the Company, along with other entities, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. 

Gulf Coast Region
ERCOT
Greens Bayou Unit 5 RMR Status — On March 29, 2016, the Company filed notice with ERCOT of its intent to mothball Greens Bayou Unit 5.  On May 27, 2016, ERCOT made a final determination that the unit is needed for reliability must-run, or RMR, service to address potential operational contingencies. On June 14, 2016, the ERCOT Board confirmed ERCOT’s determination and approved a two-year RMR agreement, effective June 1, 2016 through June 30, 2018; provided, however, ERCOT may terminate the RMR agreement at any time upon 90 days' notice.  ERCOT has a standard form contract that provides for recovery of the operating costs of the unit, together with additional performance metrics and incentives.  The estimated budget for the unit is $58 million for the contract period, which amount does not include any incentives.  Under the RMR agreement, the unit is only available to ERCOT during the months of June through September.  On July 13, 2016, ERCOT issued a request for proposals for alternatives to the RMR agreement. No alternatives were selected by ERCOT. As a result of rule changes, ERCOT determined that the RMR agreement is only needed until a new 1,100 MW combined cycle plant at Colorado Bend Generating Station comes on line, expected in mid-2017.

MISO
MISO Forward Capacity Market Design for Retail Choice — MISO staff has proposed revisions to its market design by implementing a three-year Forward Resource Auction for Illinois and the portion of Michigan with Retail Choice Load with a Sloped Demand Curve. The Company is actively participating in discussions at MISO. On November 1, 2016, MISO filed its proposal with FERC. The ultimate outcome could have an effect on overall market prices in MISO.

65

Environmental Matters
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is facing new requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations. Complying with environmental laws involves significant capital and operating expenses. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.  
A number of regulations with the potential to affect the Company and its facilities are in development, under review or have been recently promulgated by the EPA, including ESPS/NSPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent guidelines. NRG is currently reviewing the outcome and any resulting impact of recently promulgated regulations and cannot fully predict such impact until legal challenges are resolved. The Company’s environmental matters are described in the Company’s 2015 Form 10-K in Item 1, Business -  Environmental Matters  and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note 16,  Environmental Matters,  to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.
National
Clean Power Plan — The national and international attention (including the Paris Agreement) in recent years on GHG emissions has resulted in federal and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. The CPP rule faces numerous legal challenges that likely will take several years to resolve. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The U.S. Court of Appeals for the D.C. Circuit, sitting  en banc , heard oral argument on the challenges to the CPP in September 2016. A decision is expected in the next few months.
Gulf Coast Region
Texas Regional Haze — In January 2016, the EPA promulgated a final rule that requires 15 coal-fired units (at eight plants in Texas) to reduce their SO 2  rates at various times over the next five years if the rule survives legal challenges.  This Regional Haze rule was promulgated under the portion of the CAA that seeks to improve visibility at national parks.  Eight of these 15 units already have scrubbers and seven do not.  NRG owns two of the affected units, Limestone units 1 and 2, which already have scrubbers.  The rule requires that the Limestone units reduce their SO 2  emission rates by 2019.  In July 2016, the U.S. Court of Appeals for the Fifth Circuit stayed the rule pending resolution of the legal challenges.
Illinois Union Insurance Company Litigation — On October 2, 2015, the U.S. District Court for the Middle District of Louisiana issued an order granting LaGen’s motion for summary judgment on its claims for declaratory judgment and breach of contract against ILU for its failure to indemnify LaGen for the costs LaGen paid pursuant to the consent decree that resolved the NSR lawsuit which was brought by the U.S. EPA and LA DEQ against LaGen related to Big Cajun II.  The court entered judgment in favor of LaGen for approximately $27 million.  In addition, the court ruled that LaGen is entitled to approximately $7 million for future consent decree costs as they are incurred.  On October 14, 2015, ILU filed a motion to stay execution of the judgment, which was granted on October 19, 2015.  Also, on October 14, 2015, ILU filed a notice to appeal the judgment. On January 14, 2016, the U.S. District Court granted LaGen's motion for attorney's fees of approximately $2 million for the indemnity phase of the litigation. On January 29, 2016, ILU filed an appeal brief with the U.S. Court of Appeals for the Fifth Circuit.   T he Court of Appeals issued a decision on August 4, 2016 which vacated the summary judgment ruling and remanded the case to the U.S. District Court. The remanded case has been set for trial on May 8, 2017.

66

Trends Affecting Results of Operations and Future Business Performance
Wind and Solar Resource Availability

The availability of the wind and solar resources affects the financial performance of the wind and solar facilities, which may impact the Company’s overall financial performance.  Due to the variable nature of the wind and solar resources, the Company cannot predict the availability of the wind and solar resources and the potential variances from expected performance levels from quarter to quarter.  To the extent the wind and solar resources are not available at expected levels, it could have a negative impact on the Company’s financial performance for such periods.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

67

Significant Events
The following significant events occurred during 2016, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:
Acquisitions
 	 	
•	SunEdison Utility-Scale Solar and Wind Acquisition — On September 15, 2016, the Company entered into an agreement with SunEdison to acquire (i) an equity interest in a tax-equity portfolio of 530 MW mechanically-complete solar assets of which NRG’s net interest based on cash to be distributed will be 265 MW, and an additional 937 MW of solar and wind assets in development, (ii) a 154 MW construction-ready solar facility in Texas and (iii) a 182 MW portfolio of construction-ready and development solar assets in Hawaii.  The acquisition of the portfolio of solar assets in Hawaii was completed on October 7, 2016 for upfront cash consideration of $2 million and the acquisition of the 530 MW tax equity portfolio and the 937 MW development assets was completed on November 2, 2016 for upfront cash consideration of $111 million. The Company expects to pay total upfront cash consideration for the three acquisitions of $129 million, with an estimated $59 million in additional payments contingent upon future development milestones.	
 	 	
•	SunEdison Solar Distributed Generation Acquisition — On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $68 million, subject to post closing adjustments.  The Company expects to sell these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc.	
Dispositions
 	 	
•	In the first quarter of 2016, the Company completed the sales of the Seward and Shelby generating stations. On July 12, 2016, the Company sold 100% of its interests in the Rockford generating stations. Also, on July 12, 2016, GenOn completed the sale of the Aurora generating station. The completion of these dispositions resulted in a decrease of 2,205 MW from the Company's generation portfolio.	
 	 	
•	EVgo — On June 17, 2016, the Company completed the sale of a majority interest in the EVgo business to Vision Ridge Partners, which resulted in a loss of $78 million, for total consideration of approximately $39 million, consisting of $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business by Vision Ridge Partners and $7 million of future contributions by Vision Ridge Partners.	
 	 	
•	CVSR — On September 1, 2016, the Company sold its remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. NRG Yield, Inc. also assumed $496 million of non-recourse project debt as of the closing date.	
 	 	
•	Potrero Real Property — On September 26, 2016, the Company completed its sale of real property at the Potrero site for net cash proceeds of $74 million.	
Financing Activities
 	 	
•	Senior Notes Issuances and Repurchases — On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The proceeds from the issuance of the 2026 Senior Notes and the 2027 Senior Notes were utilized to redeem a portion of the Senior Notes.	
 	 	
•	Preferred Stock Repurchase — On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares of its $344.5 million 2.822% preferred stock at a price of $226 million.	
 	 	
•	Credit Facility Refinancing — On June 30, 2016, the Company completed a refinancing of its Senior Credit Facility, replacing it with the 2016 Senior Credit Facility, as more fully described in Note 8,  Debt and Capital Leases , to this Form 10-Q.	
 	 	
•	NRG Yield Operating Senior Note Offering — On August 18, 2016, NRG Yield Operating LLC issued $350 million of senior unsecured notes, or the NRG Yield Operating 2026 Senior Notes. The senior notes bear interest at 5.00% and mature in 2026.	
 	 	
•	Thermal Financing —On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Yield, Inc. received proceeds of $125 million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility for an additional $70 million of notes.	

68

Impairments
 	 	
•	During the first quarter of 2016, the Company recorded an impairment loss of $140 million on its investment in Petra Nova Parish Holdings.	
 	 	
•	During the second quarter of 2016, the Company recorded impairment losses on its Rockford generating stations and Mandalay and Ormond Beach operating units, as well as impairments relating to its residential solar business and previously purchased solar panels, totaling $115 million.	
 	 	
•	During the third quarter of 2016, the Company recorded an additional $8 million in impairments losses related to investments and $8 million in other impairments.	
Operational Matters
Sherwin Bankruptcy

The Company's Gregory cogeneration plant provided steam, processed water and a small percentage of its electrical generation to the Corpus Christi Sherwin Alumina plant pursuant to an Energy Service Agreement, or ESA. On January 11, 2016, Sherwin Alumina Company, or Sherwin, filed a voluntary petition with the United States Bankruptcy Court for the Southern District of Texas for relief under Title 11 of the United States Code. Sherwin agreed to pay all owed pre-petition amounts and, post-petition, Sherwin performed its obligations under the ESA through September 2016 when it shut down its operations. On September 28, 2016, Sherwin filed a motion with the Bankruptcy Court to reject the ESA, which includes Gregory's lease, effective September 29, 2016. Gregory objected to the rejection and is asserting its right to remain on its leasehold. The Company is currently evaluating potential options for the Gregory cogeneration plant.
Cottonwood Flooding
During March 2016, NRG's Cottonwood generating station was damaged by record flooding of the nearby Sabine River.  The generating station was returned to service in the third quarter of 2016.  The Company expects the restoration costs to be reimbursed through insurance recoveries, except for the $5 million deductible. Through September 30, 2016, NRG has expensed $5 million and collected $27.5 million of insurance proceeds from property damage and is continuing to work with insurers on further property and business interruption insurance recovery. The Company does not anticipate recognizing additional expenses related to restoration costs.

69

Consolidated Results of Operations
The following table provides selected financial information for the Company:

 	Three months ended September 30,	 	Nine months ended September 30,	
(In millions except otherwise noted)	2016	 	2015	 	Change	 	2016	 	2015	 	Change	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	
Energy revenue (a)	$	1,443	
 	 	$	1,543	
 	 	$	(100	)	 	$	3,625	
 	 	$	4,450	
 	 	$	(825	)	
Capacity revenue (a)	503	
 	 	683	
 	 	(180	)	 	1,535	
 	 	1,729	
 	 	(194	)	
Retail revenue	1,974	
 	
 	2,062	
 	 	(88	)	 	4,858	
 	 	5,369	
 	 	(511	)	
Mark-to-market for economic hedging activities	(79	)	
 	35	
 	 	(114	)	 	(592	)	 	(165	)	 	(427	)	
Contract amortization	(12	)	 	(8	)	 	(4	)	 	(41	)	 	(28	)	 	(13	)	
Other revenues (b)	123	
 	 	119	
 	 	4	
 	 	434	
 	 	308	
 	 	126	
 	
Total operating revenues	3,952	
 	 	4,434	
 	 	(482	)	 	9,819	
 	 	11,663	
 	 	(1,844	)	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	 	
Cost of sales (c)	2,110	
 	 	2,360	
 	 	(250	)	 	5,132	
 	 	6,282	
 	 	(1,150	)	
Mark-to-market for economic hedging activities	105	
 	 	42	
 	 	63	
 	 	(344	)	 	123	
 	 	(467	)	
Contract and emissions credit amortization (c)	3	
 	 	7	
 	 	(4	)	 	6	
 	 	11	
 	 	(5	)	
Operations and maintenance	485	
 	 	510	
 	 	(25	)	 	1,642	
 	 	1,782	
 	 	(140	)	
Other cost of operations	90	
 	 	123	
 	 	(33	)	 	302	
 	 	353	
 	 	(51	)	
Total cost of operations	2,793	
 	 	3,042	
 	 	(249	)	 	6,738	
 	 	8,551	
 	 	(1,813	)	
Depreciation and amortization	357	
 	 	382	
 	 	(25	)	 	979	
 	 	1,173	
 	 	(194	)	
Impairment losses	8	
 	 	263	
 	 	(255	)	 	123	
 	 	263	
 	 	(140	)	
Selling and marketing	107	
 	 	138	
 	 	(31	)	 	291	
 	 	364	
 	 	(73	)	
General and administrative	175	
 	 	189	
 	 	(14	)	 	511	
 	 	514	
 	 	(3	)	
Acquisition-related transaction and integration costs	—	
 	 	3	
 	 	(3	)	 	7	
 	 	16	
 	 	(9	)	
Development activity expenses	23	
 	 	38	
 	 	(15	)	 	67	
 	 	109	
 	 	(42	)	
Total operating costs and expenses	3,463	
 	 	4,055	
 	 	(592	)	 	8,716	
 	
 	10,990	
 	 	(2,274	)	
Gain on sale of assets and postretirement benefits curtailment	266	
 	 	—	
 	 	266	
 	 	215	
 	 	14	
 	 	201	
 	
Operating Income	755	
 	 	379	
 	 	376	
 	 	1,318	
 	 	687	
 	 	631	
 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	16	
 	 	24	
 	 	(8	)	 	13	
 	 	29	
 	 	(16	)	
Impairment loss on investment	(8	)	 	—	
 	 	(8	)	 	(147	)	 	—	
 	 	(147	)	
Other income, net	9	
 	 	4	
 	 	5	
 	 	35	
 	 	27	
 	 	8	
 	
Loss on debt extinguishment	(50	)	 	(2	)	 	(48	)	 	(119	)	 	(9	)	 	(110	)	
Interest expense	(280	)	 	(291	)	 	11	
 	 	(841	)	 	(855	)	 	14	
 	
Total other expense	(313	)	 	(265	)	 	(48	)	 	(1,059	)	 	(808	)	 	(251	)	
Income/(Loss) before Income Taxes	442	
 	 	114	
 	 	328	
 	 	259	
 	 	(121	)	 	380	
 	
Income tax expense/(benefit)	49	
 	 	47	
 	 	2	
 	 	95	
 	 	(43	)	 	138	
 	
Net Income/(Loss)	393	
 	 	67	
 	 	326	
 	 	164	
 	 	(78	)	 	242	
 	
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	(9	)	 	1	
 	 	(10	)	 	(49	)	 	(10	)	 	(39	)	
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	402	
 	 	$	66	
 	 	$	336	
 	 	$	213	
 	 	$	(68	)	 	$	281	
 	
Business Metrics	 	 	 	 	

Average natural gas price — Henry Hub ($/MMBtu)	$	2.81	
 	 	$	2.77	
 	 	1	%	 	$	2.29	
 	 	$	2.80	
 	 	(18	)%	
(a) Includes realized gains and losses from financially settled transactions.
(b) Includes unrealized trading gains and losses.
(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.

70

Management’s discussion of the results of operations for the three months ended September 30, 2016, and 2015
Income before income taxes — The pre-tax income of $442 million for the three months ended September 30, 2016, compared to pre-tax income of $114 million for the three months ended September 30, 2015, primarily reflects:
•a decrease of $440 million in other operating costs comprised of operations and maintenance expense, other costs of operations, depreciation and amortization, selling and marketing expense, general and administrative expense, acquisition-related transaction and integration costs, development activity expense, and gain on sale of assets;
•a decrease of $247 million in impairment losses;
partially offset by:
 	 	
•	an increase of $40 million in other expenses, primarily relating to loss on debt extinguishment; and	
•a decrease in gross margin of $319 million comprised of a decrease in Retail Mass gross margin of $245 million and a decrease in Generation gross margin of $107 million, partially offset by an increase in NRG Yield gross margin of $18 million and an increase in Renewables gross margin of $15 million.
Net Income — The increase in net income of $326 million primarily reflects the drivers discussed above, including an income tax expense of $49 million for the three months ended September 30, 2016, compared to an income tax expense of $47 million in the comparable period in 2015.
Electricity Prices
The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the three months ended September 30, 2016 and 2015. The average on-peak power price decreases in certain markets are primarily due to the decrease in natural gas prices for the three months ended September 30, 2016 as compared to the same period in 2015.  The average on-peak power price increases in certain markets are primarily due to the increase in market heat rates for the three months ended September 30, 2016 as compared to the same period in 2015.

 	 	 	 	 	 	 	 	 	 	 	
 	Average on Peak Power Price ($/MWh) (a)	
 	Three months ended September 30,	
Region	2016	 	2015	 	Change %	
Gulf Coast (b)	 	 	 	 	 	
ERCOT - Houston	$	33.12	
 	 	$	34.87	
 	 	(5	)%	
ERCOT - North	30.47	
 	 	35.22	
 	 	(13	)%	
MISO - Louisiana Hub	39.92	
 	 	35.03	
 	 	14	 %	
East	 	 	 	 	
 	
    NY J/NYC	42.60	
 	 	41.32	
 	 	3	 %	
    NY A/West NY	46.22	
 	 	40.68	
 	 	14	 %	
    NEPOOL	42.40	
 	 	42.68	
 	 	(1	)%	
    PEPCO (PJM)	42.60	
 	 	42.62	
 	 	—	 %	
    PJM West Hub	38.89	
 	 	39.35	
 	 	(1	)%	
West	 	 	 	 	
 	
CAISO - NP15	38.23	
 	 	37.20	
 	 	3	 %	
CAISO - SP15	40.43	
 	 	38.20	
 	 	6	 %	
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(b) Gulf Coast region also transacts in PJM - West Hub.

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended September 30, 2016, and 2015, which reflects the impact of settled hedges.

 	Average Realized Power Price ($/MWh)	
 	Three months ended September 30,	
Region	2016	 	2015	 	Change %	
Gulf Coast	$	38.96	
 	 	$	42.65	
 	 	(9	)%	
East	54.36	
 	 	44.62	
 	 	22	 %	
West	43.30	
 	 	45.34	
 	 	(4	)%	

71

Though the average on peak power prices have increased on average by 2%, average realized prices by region for the Company have either increased or decreased at a slower rate year-over-year due to the Company's multi-year hedging program and the success of the Company's commercial operations team that optimizes the value of the assets on a daily basis.

Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue and other revenue, less cost of fuels and other cost of sales.
The economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended September 30, 2016 and 2015:

72

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Three months ended September 30, 2016	
 	Generation	 	 	 	 	 	 	 	 	 	 	
(In millions)	Gulf Coast	 	East	 	West	 	International	 	Business Solutions	 	Eliminations	 	Subtotal	 	Retail Mass	 	Renewables	 	NRG Yield	 	Eliminations/Corporate	 	Total	
Energy revenue	$	679	
 	 	$	741	
 	 	$	86	
 	 	$	—	
 	 	$	1	
 	 	$	(21	)	 	$	1,486	
 	 	$	—	
 	 	$	126	
 	 	$	158	
 	 	$	(327	)	 	$	1,443	
 	
Capacity revenue	72	
 	 	243	
 	 	59	
 	 	—	
 	 	45	
 	 	—	
 	 	419	
 	 	—	
 	 	—	
 	 	86	
 	 	(2	)	 	503	
 	
Retail revenue	—	
 	 	—	
 	 	—	
 	 	—	
 	 	343	
 	 	—	
 	 	343	
 	 	1,618	
 	 	—	
 	 	—	
 	 	13	
 	 	1,974	
 	
Mark-to-market for economic hedging activities	179	
 	 	(94	)	 	9	
 	 	—	
 	 	2	
 	 	(32	)	 	64	
 	 	—	
 	 	1	
 	 	—	
 	 	(144	)	 	(79	)	
Contract amortization	4	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	4	
 	 	1	
 	 	—	
 	 	(17	)	 	—	
 	 	(12	)	
Other revenue	53	
 	 	18	
 	 	2	
 	 	1	
 	 	4	
 	 	(4	)	 	74	
 	 	—	
 	 	13	
 	 	45	
 	 	(9	)	 	123	
 	
Operating revenue	987	
 	 	908	
 	 	156	
 	 	1	
 	 	395	
 	 	(57	)	 	2,390	
 	 	1,619	
 	 	140	
 	 	272	
 	 	(469	)	 	3,952	
 	
Cost of fuel	(339	)	 	(358	)	 	(50	)	 	—	
 	 	—	
 	 	—	
 	 	(747	)	 	(1	)	 	(1	)	 	(7	)	 	—	
 	 	(756	)	
Other cost of sales (a)	(115	)	 	(94	)	 	(10	)	 	—	
 	 	(331	)	 	21	
 	 	(529	)	 	(1,155	)	 	—	
 	 	(11	)	 	341	
 	 	(1,354	)	
Mark-to-market for economic hedging activities	28	
 	 	56	
 	 	(6	)	 	—	
 	 	(119	)	 	32	
 	 	(9	)	 	(240	)	 	—	
 	 	—	
 	 	144	
 	 	(105	)	
Contract and emission credit amortization	(6	)	 	6	
 	 	—	
 	 	—	
 	 	(2	)	 	—	
 	 	(2	)	 	—	
 	 	—	
 	 	—	
 	 	(1	)	 	(3	)	
Gross margin	$	555	
 	 	$	518	
 	
 	$	90	
 	 	$	1	
 	 	$	(57	)	 	$	(4	)	 	$	1,103	
 	 	$	223	
 	 	$	139	
 	 	$	254	
 	 	$	15	
 	 	$	1,734	
 	
Less: Mark-to-market for economic hedging activities, net	207	
 	 	(38	)	 	3	
 	 	—	
 	 	(117	)	 	—	
 	 	55	
 	 	(240	)	 	1	
 	 	—	
 	 	—	
 	 	(184	)	
Less: Contract and emission credit amortization, net	(2	)	 	6	
 	 	—	
 	 	—	
 	 	(2	)	 	—	
 	 	2	
 	 	1	
 	 	—	
 	 	(17	)	 	(1	)	 	(15	)	
Economic gross margin	$	350	
 	 	$	550	
 	
 	$	87	
 	
 	$	1	
 	 	$	62	
 	
 	$	(4	)	
 	$	1,046	
 	
 	$	462	
 	
 	$	138	
 	
 	$	271	
 	
 	$	16	
 	
 	$	1,933	
 	
Business Metrics	
MWh sold (thousands) (b)(c)	17,430	
 	 	15,544	
 	 	1,986	
 	 	 	 	 	 	 	 	 	 	 	 	978	
 	 	1,744	
 	 	 	 	 	
MWh generated (thousands) (d)	15,980	
 	 	13,438	
 	 	1,464	
 	 	 	 	 	 	 	 	 	 	 	 	978	
 	 	2,372	
 	 	 	 	 	
Electricity sales volume — GWh	 	 	 	 	 	 	 	 	5,146	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Includes purchased energy, capacity and emissions credits	
(b) MWh sold excludes generation at facilities in the East,West and NRG Yield that generate revenue under capacity agreements.	
(c) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield.	
(d) Does not include thermal MWh of 122 thousand or MWt of 496 thousand for thermal generated by NRG Yield.	

73

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Three months ended September 30, 2015	
 	Generation	 	 	 	 	 	 	 	 	 	 	
(In millions)	Gulf Coast	 	East	 	West	 	International	 	Business Solutions	 	Eliminations	 	Subtotal	 	Retail Mass	 	Renewables	 	NRG Yield	 	Eliminations/Corporate	 	Total	
Energy revenue	$	765	
 	 	$	760	
 	 	$	126	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	1,651	
 	 	$	—	
 	 	$	114	
 	 	$	138	
 	 	$	(360	)	 	$	1,543	
 	
Capacity revenue	88	
 	 	364	
 	 	73	
 	 	—	
 	 	72	
 	 	—	
 	 	597	
 	 	—	
 	 	—	
 	 	89	
 	 	(3	)	 	683	
 	
Retail revenue	—	
 	 	—	
 	 	—	
 	 	—	
 	 	367	
 	 	—	
 	 	367	
 	 	1,698	
 	 	—	
 	 	—	
 	 	(3	)	 	2,062	
 	
Mark-to-market for economic hedging activities	18	
 	 	(35	)	 	15	
 	 	—	
 	 	1	
 	 	—	
 	 	(1	)	 	—	
 	 	—	
 	 	(2	)	 	38	
 	 	35	
 	
Contract amortization	4	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	4	
 	 	1	
 	 	1	
 	 	(14	)	 	—	
 	 	(8	)	
Other revenue	52	
 	 	19	
 	 	2	
 	 	1	
 	 	6	
 	 	(3	)	 	77	
 	 	—	
 	 	9	
 	 	45	
 	 	(12	)	 	119	
 	
Operating revenue	927	
 	 	1,108	
 	 	216	
 	 	1	
 	 	446	
 	 	(3	)	 	2,695	
 	 	1,699	
 	 	124	
 	 	256	
 	 	(340	)	 	4,434	
 	
Cost of fuel	(378	)	 	(370	)	 	(75	)	 	—	
 	 	—	
 	 	—	
 	 	(823	)	 	(1	)	 	(1	)	 	(8	)	 	—	
 	 	(833	)	
Other cost of sales (a)	(87	)	 	(145	)	 	(15	)	 	—	
 	 	(379	)	 	—	
 	 	(626	)	 	(1,254	)	 	1	
 	 	(12	)	 	364	
 	 	(1,527	)	
Mark-to-market for economic hedging activities	13	
 	 	4	
 	 	(7	)	 	—	
 	 	(38	)	 	—	
 	 	(28	)	 	24	
 	 	—	
 	 	—	
 	 	(38	)	 	(42	)	
Contract and emission credit amortization	(7	)	 	5	
 	 	(3	)	 	—	
 	 	(2	)	 	—	
 	 	(7	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(7	)	
Gross margin	$	468	
 	 	$	602	
 	 	$	116	
 	 	$	1	
 	 	$	27	
 	 	$	(3	)	 	$	1,211	
 	 	$	468	
 	 	$	124	
 	 	$	236	
 	 	$	(14	)	 	$	2,025	
 	
Less: Mark-to-market for economic hedging activities, net	31	
 	 	(31	)	 	8	
 	 	—	
 	 	(37	)	 	—	
 	 	(29	)	 	24	
 	 	—	
 	 	(2	)	 	—	
 	 	(7	)	
Less: Contract and emission credit amortization, net	(3	)	 	5	
 	 	(3	)	 	—	
 	 	(2	)	 	—	
 	 	(3	)	 	1	
 	 	1	
 	 	(14	)	 	—	
 	 	(15	)	
Economic gross margin	$	440	
 	 	$	628	
 	 	$	111	
 	 	$	1	
 	 	$	66	
 	 	$	(3	)	 	$	1,243	
 	 	$	443	
 	 	$	123	
 	 	$	252	
 	 	$	(14	)	 	$	2,047	
 	
Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (thousands) (b)(c)	17,936	
 	 	17,727	
 	 	2,779	
 	 	 	 	 	 	 	 	 	 	 	 	930	
 	 	1,596	
 	 	 	 	 	
MWh generated (thousands)  (d)	17,283	
 	 	14,118	
 	 	1,964	
 	 	 	 	 	 	 	 	 	 	 	 	930	
 	 	2,553	
 	 	 	 	 	
Electricity sales volume — GWh	 	 	 	 	 	 	 	 	5,289	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Includes purchased energy, capacity and emissions credits	
(b) MWh sold excludes generation at facilities in the East,West and NRG Yield that generate revenue under capacity agreements.	
(c) Does not include thermal MWh of 92 thousand or MWt of 468 thousand for thermal sold by NRG Yield.	
(d) Does not include thermal MWh of 92 thousand or MWt of 468 thousand for thermal generated by NRG Yield.	
The table below represents the weather metrics for the three months ended September 30, 2016 and 2015:

 	Three months ended September 30,	 	 	 	 	 	 	 	 	
Weather Metrics	Gulf Coast	 	East	 	West	 	 	 	 	 	 	 	 	
2016	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs (a)	1,655	
 	 	947	
 	 	666	
 	 	 	 	 	 	 	 	 	
HDDs (a)	—	
 	 	32	
 	 	14	
 	 	 	 	 	 	 	 	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs	1,652	
 	 	824	
 	 	772	
 	 	 	 	 	 	 	 	 	
HDDs	—	
 	 	26	
 	 	7	
 	 	 	 	 	 	 	 	 	
10 year average	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs	1,597	
 	 	746	
 	 	631	
 	 	 	 	 	 	 	 	 	
HDDs	4	
 	 	76	
 	 	22	

(a)	National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.	

74

Generation gross margin and economic gross margin
The below tables present the changes in Generation gross margin and economic gross margin which include intercompany sales, during the three months ended September 30, 2016, compared to the same period in 2015:

(In millions)	Gross Margin (increase/(decrease))	 	Economic Gross Margin (increase/(decrease))	
Gulf Coast region	$	87	
 	 	$	(90	)	
East region	(84	)	 	(78	)	
West region	(26	)	 	(24	)	
Business Solutions	(84	)	 	(4	)	
 	$	(107	)	 	$	(196	)	

The decrease in Generation gross margin and economic gross margin was driven by:

Gulf Coast Region

 	(In millions)	
Lower gross margin due to lower average realized energy prices due to a decline in natural gas prices	$	(41	)	
Lower gross margin due to 4% lower coal generation mainly in Texas, which was driven by an increase in unplanned outages and the timing of planned outages	(29	)	
Lower gross margin, primarily in South Central due to a 63% decrease in PJM cleared auction capacity prices and a 19% decrease in PJM capacity volumes	(17	)	
Other	(3	)	
Decrease in economic gross margin	$	(90	)	
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	176	
 	
Increase in contract and emission credit amortization	1	
 	
Increase in gross margin	$	87	
 	
East Region    

 	(In millions)	
Lower gross margin due to a 31% decrease in PJM cleared auction capacity prices, as well as a 9% decrease in PJM capacity volumes due to asset sales partially offset by reduced capacity purchases due to plant deactivations	$	(68	)	
Lower gross margin as a result of a 7% decrease in average realized energy prices due to a decline in natural gas prices in 2016 coupled with a 5% decrease in generation volume primarily due to the sale of the Seward generating station	(66	)	
Lower gross margin driven primarily by a 12% decrease in New York and New England capacity prices as well as the expiration of the Dunkirk RSS contract, and a 3% decrease in capacity volume related to the retirement of Huntley	(31	)	
Lower gross margin due to lower load contracted volumes and expiration of contracts	(13	)	
Higher gross margin due to the closure and financial settlement of hedge positions with a counterparty that would have otherwise been realized in 2017, 2018, and 2019	98	
 	
Higher gross margin due to commercial optimization activities and other	2	
 	
Decrease in economic gross margin	$	(78	)	
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(7	)	
Increase in contract and emission credit amortization	1	
 	
Decrease in gross margin	$	(84	)	

75

West Region

 	(In millions)	
Lower gross margin resulting from a 15% decrease in capacity volumes, and a 5% decrease in capacity prices due to higher reserve margins driven by more competition in certain areas	$	(14	)	
Lower gross margin resulting from a 29% decrease in generation due to plant retirements, forced outages
 and a 5% decrease in average realized energy prices	(11	)	
Other	1	
 	
Decrease in economic gross margin	$	(24	)	
Decrease in mark-to-market for economic hedging activities driven by a decrease in the value of open positions	(5	)	
Increase in contract and emission credit amortization	3	
 	
Decrease in gross margin	$	(26	)	

Business Solutions

 	(In millions)	
Lower gross margin from the demand response business in 2016 due to lower commitments and pricing in PJM and New York capacity markets	$	(6	)	
Higher gross margin driven by lower supply costs	2	
 	
Decrease in economic gross margin	$	(4	)	
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(80	)	
Decrease in gross margin	$	(84	)	

76

Retail Mass gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail Mass.

 	Three months ended September 30,	
(In millions except otherwise noted)	2016	 	2015	
Retail Mass revenue	$	1,571	
 	 	$	1,649	
 	
Supply management revenue	47	
 	 	49	
 	
Contract amortization	1	
 	 	1	
 	
Operating revenue (a)	1,619	
 	 	1,699	
 	
Cost of sales (b)	(1,156	)	 	(1,255	)	
Mark-to-market for economic hedging activities	(240	)	 	24	
 	
Gross Margin	$	223	
 	 	$	468	
 	
Less: Mark-to-market for economic hedging activities, net	(240	)	 	24	
 	
Less: Contract and emission credit amortization, net	1	
 	 	1	
 	
Economic Gross Margin	$	462	
 	 	$	443	

Business Metrics	 	 	 	
Electricity sales volume — GWh - Gulf Coast	11,996	
 	 	11,585	
 	
Electricity sales volume — GWh - All other regions	1,986	
 	 	2,099	
 	
Average Retail Mass customer count (in thousands) (c)	2,786	
 	 	2,767	
 	
Ending Retail Mass customer count (in thousands) (c)	2,797	
 	 	2,762	

(a)	Includes intercompany sales of $0 million and $2 million in 2016 and 2015, respectively, representing sales from Retail Mass to the Gulf Coast region.	
 	 	
(b)	Includes intercompany purchases of $333 million and $348 million in 2016 and 2015.	
 	 	
(c)	Includes Retail Mass Recurring Customers and excludes Discrete Customers.	

Retail Mass gross margin decreased $245 million and economic gross margin increased $19 million for the three months ended September 30, 2016, compared to the same period in 2015, due to:

 	(In millions)	
Higher gross margin from an increase in load served of 482,000 MWhs due to warmer summer weather in 2016 as compared to 2015	$	14	
 	
Higher gross margin due to lower supply costs of $120 million or approximately $9 per MWh driven by a decrease in natural gas prices, partially offset by lower rates to customers of $115 million or $9 per MWh	5	
 	
Increase in economic gross margin	$	19	
 	
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(264	)	
Decrease in gross margin	$	(245	)	

Renewables gross margin and economic gross margin
Renewables gross margin increased $15 million and economic gross margin increased $15 million for the three months ended September 30, 2016, compared to the same period in 2015, primarily driven by a 23% increase in generation at the Ivanpah solar plant and generation from the Guam solar plant that reached COD in the third quarter of 2015.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin increased $18 million and economic gross margin increased $19 million for the three months ended September 30, 2016, compared to the same period in 2015, primarily related to a 24% increase in volume generated at Alta I-V wind projects, as well as 5% increase in solar generation, primarily at CVSR.

77

Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $177 million during the three months ended September 30, 2016, compared to the same period in 2015.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:

 	Three months ended September 30, 2016	
 	 	 	Generation	 	 	 	 	 	 	
 	Retail Mass	 	Gulf Coast	 	East	 	West	 	Business Solutions	 	Renewables	 	Elimination(a)	 	Total	
 	(In millions)	
Mark-to-market results in operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	—	
 	 	$	8	
 	 	$	(30	)	 	$	(3	)	 	$	—	
 	 	$	—	
 	 	$	(78	)	 	$	(103	)	
Reversal of acquired gain positions related to economic hedges	—	
 	 	—	
 	 	(13	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(13	)	
Net unrealized gains/(losses) on open positions related to economic hedges	—	
 	 	171	
 	 	(51	)	 	12	
 	 	2	
 	 	1	
 	 	(98	)	 	37	
 	
Total mark-to-market gains/(losses) in operating revenues	$	—	
 	 	$	179	
 	 	$	(94	)	 	$	9	
 	 	$	2	
 	 	$	1	
 	 	$	(176	)	 	$	(79	)	
Mark-to-market results in operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(39	)	 	$	7	
 	 	$	20	
 	 	$	—	
 	 	$	(7	)	 	$	—	
 	 	$	78	
 	 	$	59	
 	
Reversal of acquired gain positions related to economic hedges	—	
 	 	—	
 	 	—	
 	 	(5	)	 	(1	)	 	—	
 	 	—	
 	 	(6	)	
Net unrealized (losses)/gains on open positions related to economic hedges	(201	)	 	21	
 	 	36	
 	 	(1	)	 	(111	)	 	—	
 	 	98	
 	 	(158	)	
Total mark-to-market (losses)/gains in operating costs and expenses	$	(240	)	 	$	28	
 	 	$	56	
 	 	$	(6	)	 	$	(119	)	 	$	—	
 	 	$	176	
 	 	$	(105	)	
 	 	
(a)	Represents the elimination of the intercompany activity between Retail Mass and Generation.	

78

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Three months ended September 30, 2015	
 	 	 	Generation	 	 	 	 	 	 	 	 	
 	Retail Mass	 	Gulf Coast	 	East	 	West	 	Business Solutions	 	Renewables	 	NRG Yield	 	Elimination(a)	 	Total	
 	(In millions)	
Mark-to-market results in operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	
 	 	$	(1	)	 	$	(24	)	 	$	3	
 	 	$	—	
 	 	$	(1	)	 	$	—	
 	 	$	74	
 	 	$	51	
 	
Reversal of acquired gain positions related to economic hedges	—	
 	 	—	
 	 	(19	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(19	)	
Net unrealized gains/(losses) on open positions related to economic hedges	—	
 	 	19	
 	 	8	
 	 	12	
 	 	1	
 	 	—	
 	 	(1	)	 	(36	)	 	3	
 	
Total mark-to-market gains/(losses) in operating revenues	$	—	
 	 	$	18	
 	 	$	(35	)	 	$	15	
 	 	$	1	
 	 	$	(1	)	 	$	(1	)	 	$	38	
 	 	$	35	
 	
Mark-to-market results in operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(15	)	 	$	9	
 	 	$	4	
 	 	$	—	
 	 	$	(4	)	 	$	—	
 	 	$	—	
 	 	$	(74	)	 	$	(80	)	
Reversal of acquired gain positions related to economic hedges	(4	)	 	—	
 	 	—	
 	 	(8	)	 	(2	)	 	—	
 	 	—	
 	 	—	
 	 	(14	)	
Net unrealized gains/(losses) on open positions related to economic hedges	43	
 	 	4	
 	 	—	
 	 	1	
 	 	(32	)	 	—	
 	 	—	
 	 	36	
 	 	52	
 	
Total mark-to-market gains/(losses) in operating costs and expenses	$	24	
 	 	$	13	
 	 	$	4	
 	 	$	(7	)	 	$	(38	)	 	$	—	
 	 	$	—	
 	 	$	(38	)	 	$	(42	)	
 	 	
(a)	Represents the elimination of the intercompany activity between Retail Mass, Generation, and NRG Yield.	
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the three months ended September 30, 2016, the $79 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts, partially offset by an increase in value of open positions as a result of decreases in gas and electricity prices. The $105 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas and ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.
For the three months ended September 30, 2015, the $35 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, partially offset by the reversal of acquired contracts. The $42 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts, partially offset by an increase in value of open positions as a result of increases in ERCOT heat rate.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2016, and 2015. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.

 	Three months ended September 30,	
(In millions)	2016	 	2015	
Trading gains/(losses)	 	 	 	
Realized	$	20	
 	 	$	(1	)	
Unrealized	(5	)	 	(1	)	
Total trading gains/(losses)	$	15	
 	 	$	(2	)	
In addition, trading activities reflect an increase in gross margin of $18 million, reflected in the Corporate segment, for the three months ended September 30, 2016, as compared to the three months ended September 30, 2015.

79

Operations and Maintenance Expense

 	Generation	 	Retail Mass	 	Renewables	 	NRG Yield	 	Corporate	 	 	 	
 	Gulf Coast	 	East	 	West	 	Business Solutions	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	(In millions)	 	 	 	 	 	 	
Three months ended September 30, 2016	$	143	
 	 	$	190	
 	 	$	34	
 	 	$	5	
 	 	$	54	
 	 	$	19	
 	 	$	36	
 	 	$	4	
 	 	$	485	
 	 	 	 	 	 	 	
Three months ended September 30, 2015	128	
 	 	223	
 	 	29	
 	 	6	
 	 	50	
 	 	39	
 	 	38	
 	 	(3	)	 	510	
 	 	 	 	 	 	 	
Operations and maintenance expense decreased by $25 million for the three months ended September 30, 2016, compared to the same period in 2015, due to the following:

 	(In millions)	
Decrease in East operating costs due to the sale of the Seward and Shelby generating stations in 2016	$	(17	)	
Decrease in East operations and maintenance expense due to deactivations of the Huntley and Dunkirk facilities	(17	)	
Increase in Gulf Coast operations and maintenance expense primarily related to the timing of outages at Cottonwood	14	
 	
Other	(5	)	
 	$	(25	)	
Other Cost of Operations
Other cost of operations, comprised of asset retirement expense, insurance expense and property and other tax expense, decreased by $33 million for the three months ended September 30, 2016, compared to the same period in 2015, primarily due to a reduction in property tax expense for Chalk Point and Dickerson.
Depreciation and Amortization

 	Generation	 	Retail Mass	 	Renewables	 	NRG Yield	 	Corporate	 	 	 	
 	Gulf Coast	 	East	 	West	 	Business Solutions	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	(In millions)	 	 	 	 	 	 	
Three months ended September 30, 2016	$	125	
 	 	$	50	
 	 	$	16	
 	 	$	2	
 	 	$	25	
 	 	$	48	
 	 	$	75	
 	 	$	16	
 	 	$	357	
 	 	 	 	 	 	 	
Three months ended September 30, 2015	143	
 	 	63	
 	 	11	
 	 	3	
 	 	30	
 	 	46	
 	 	69	
 	 	17	
 	 	382	
 	 	 	 	 	 	 	
Depreciation and amortization expense decreased by $25 million for the three months ended September 30, 2016, compared to the same period in 2015, due to a decrease in depreciation expense for facilities impaired at the end of 2015 and asset sales during 2016.
Selling, Marketing, General and Administrative Expenses
Selling, marketing, general and administrative expenses are comprised of the following:

 	Generation	 	Retail Mass (b)	 	Renewables(c)	 	NRG Yield	 	Corporate(d)	 	 	 	
 	Gulf Coast	 	East	 	West	 	Business Solutions (a)	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	(In millions)	 	 	 	 	 	 	
Three months ended September 30, 2016	$	31	
 	 	$	43	
 	 	$	7	
 	 	$	20	
 	 	$	118	
 	 	$	12	
 	 	$	4	
 	 	$	47	
 	 	$	282	
 	 	 	 	 	 	 	
Three months ended September 30, 2015	41	
 	 	53	
 	 	11	
 	 	22	
 	 	116	
 	 	16	
 	 	3	
 	 	65	
 	 	327	
 	 	 	 	 	 	 	
(a) Includes selling and marketing expense of $11 million for three months ended September 30, 2016 and 2015.
(b) Includes selling and marketing expense of $77 million and $75 million for the three months ended September 30, 2016 and 2015.
(c) Includes selling and marketing expense of $1 million and $2 million for the three months ended September 30, 2016 and 2015.
(d) Includes selling and marketing expense of $17 million and $49 million for the three months ended September 30, 2016 and 2015.

Selling, marketing, general and administrative expenses decreased by $45 million for the three months ended September 30, 2016, compared to the same period in 2015, due primarily to the Company's continued focus on cost management in 2016.

80

Development Activity Expenses
Development activity expenses decreased by $15 million for the three months ended September 30, 2016, compared to the same period in 2015, due to the strategic move for a more focused development program primarily related to Renewables and other corporate initiatives and the sale of EVgo in June 2016.
Gain on Sale of Assets
During the three months ended September 30, 2016, the Company recognized a $266 million gain on sale of assets related to the sale of the Aurora generating station and real property at our Potrero location, as described in Note 3,  Business Acquisitions and Dispositions.
Loss on Debt Extinguishment
A loss on debt extinguishment of $50 million was recorded for the three months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.
Interest Expense
NRG's interest expense decreased by $11 million for the three months ended September 30, 2016, compared to the same period in 2015 due to the following:

 	(In millions)	
Decrease due to the redemption of outstanding bonds related to NRG Peakers Finance Company	$	(8	)	
Decrease due to the repurchases of Senior Notes at the end of 2015 and first three quarters of 2016	(3	)	
Increase in derivative interest expense from changes in fair value of interest rate swaps	3	
 	
Increase due to $200 million of debt issued by CVSR Holdco in August 2016	2	
 	
Other	(5	)	
 	$	(11	)	
Income Tax Expense
For the three months ended September 30, 2016, NRG recorded an income tax expense of $49 million on pre-tax income of $442 million. For the same period in 2015, NRG recorded an income tax expense of $47 million on pre-tax income of $114 million. The effective tax rate was 11.1% and 41.2% for the three months ended September 30, 2016, and 2015, respectively.
For the three months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the change in valuation allowance, partially offset by state tax expense and tax expense attributable to consolidated partnerships.
For the three months ended September 30, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to non-deductible impairment of goodwill, partially offset by production tax credits generated from our wind assets.
Net (loss)/ income attributable to noncontrolling interests and redeemable noncontrolling interests
For the three months ended September 30, 2016, and 2015, net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, offset by NRG Yield, Inc.'s share of net income.

81

Management’s discussion of the results of operations for the nine months ended September 30, 2016, and 2015
Income before income taxes — The pre-tax income of $259 million for the nine months ended September 30, 2016, compared to pre-tax loss of $121 million for the nine months ended September 30, 2015, primarily reflects:
•a decrease of $815 million in other operating costs comprised of operations and maintenance expense, other costs of operations, depreciation and amortization, selling and marketing expense, general and administrative expense, acquisition-related transaction and integration costs, development activity expense, and gain on sale of assets;
partially offset by:
•an increase of $104 million in other expenses, primarily relating to loss on debt extinguishment; and
•a decrease in gross margin of $324 million comprised of a decrease in Generation gross margin of $472 million, partially offset by an increase in NRG Yield gross margin of $64 million, an increase in Retail Mass gross margin of $51 million, and an increase in Renewables gross margin of $33 million.
Net Income — The increase in net income of $242 million primarily reflects the drivers discussed above, including an income tax expense of $95 million for the nine months ended September 30, 2016, compared to an income tax benefit of $43 million in the comparable period in 2015.
Electricity Prices
The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2016, and 2015. Average on-peak power prices decreased primarily due to the decrease in natural gas prices for the nine months ended September 30, 2016 as compared to the same period in 2015.

 	Average on Peak Power Price ($/MWh) (a)	
 	Nine months ended September 30,	
Region	2016	 	2015	 	Change %	
Gulf Coast (b)	 	 	 	 	 	
ERCOT - Houston	$	25.97	
 	 	$	29.77	
 	 	(13	)%	
ERCOT - North	24.14	
 	 	29.85	
 	 	(19	)%	
MISO - Louisiana Hub	33.50	
 	 	37.14	
 	 	(10	)%	
East	 	 	 	 	
 	
    NY J/NYC	35.07	
 	 	52.51	
 	 	(33	)%	
    NY A/West NY	37.37	
 	 	44.46	
 	 	(16	)%	
    NEPOOL	33.82	
 	 	53.31	
 	 	(37	)%	
    PEPCO (PJM)	38.16	
 	 	49.52	
 	 	(23	)%	
    PJM West Hub	33.97	
 	 	45.33	
 	 	(25	)%	
West	 	 	 	 	
 	
CAISO - NP15	29.42	
 	 	37.01	
 	 	(21	)%	
CAISO - SP15	30.29	
 	 	32.86	
 	 	(8	)%	
(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs.
(b) Gulf Coast region also transacts in PJM - West Hub.

The following table summarizes average realized power prices for each region in which NRG operates for the nine months ended September 30, 2016, and 2015, which reflects the impact of settled hedges.

 	Average Realized Power Price ($/MWh)	
 	Nine months ended September 30,	
Region	2016	 	2015	 	Change %	
Gulf Coast	$	38.54	
 	 	$	41.57	
 	 	(7	)%	
East	57.85	
 	 	51.93	
 	 	11	 %	
West	39.17	
 	 	44.29	
 	 	(12	)%	
Though the average on peak power prices have decreased on average by 22%, average realized prices by region for the Company have either increased or decreased at a slower rate year-over-year due to the Company's multi-year hedging program and the success of the Company's commercial operations team that optimizes the value of the assets on a daily basis.

82

Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue and other revenue, less cost of fuels and other cost of sales.
The economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2016 and 2015:

83

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Nine months ended September 30, 2016	
 	Generation	 	 	 	 	 	 	 	 	 	 	
(In millions)	Gulf Coast	 	East	 	West	 	International	 	Business Solutions	 	Eliminations	 	Subtotal	 	Retail Mass	 	Renewables	 	NRG Yield	 	Eliminations/Corporate	 	Total	
Energy revenue	$	1,676	
 	 	$	1,743	
 	 	$	160	
 	 	$	—	
 	 	$	1	
 	 	$	(21	)	 	$	3,559	
 	 	$	—	
 	 	$	303	
 	 	$	459	
 	 	$	(696	)	 	$	3,625	
 	
Capacity revenue	222	
 	 	861	
 	 	140	
 	 	—	
 	 	74	
 	 	—	
 	 	1,297	
 	 	—	
 	 	—	
 	 	256	
 	 	(18	)	 	1,535	
 	
Retail revenue	—	
 	 	—	
 	 	—	
 	 	—	
 	 	966	
 	 	—	
 	 	966	
 	 	3,868	
 	 	—	
 	 	—	
 	 	24	
 	 	4,858	
 	
Mark-to-market for economic hedging activities	(270	)	 	(239	)	 	(2	)	 	—	
 	 	—	
 	 	(32	)	 	(543	)	 	—	
 	 	—	
 	 	—	
 	 	(49	)	 	(592	)	
Contract amortization	11	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	11	
 	 	—	
 	 	(1	)	 	(51	)	 	—	
 	 	(41	)	
Other revenue	191	
 	 	58	
 	 	58	
 	 	2	
 	 	12	
 	 	(12	)	 	309	
 	 	—	
 	 	33	
 	 	125	
 	 	(33	)	 	434	
 	
Operating revenue	1,830	
 	 	2,423	
 	 	356	
 	 	2	
 	 	1,053	
 	 	(65	)	 	5,599	
 	 	3,868	
 	 	335	
 	 	789	
 	 	(772	)	 	9,819	
 	
Cost of fuel	(770	)	 	(774	)	 	(90	)	 	—	
 	 	—	
 	 	—	
 	 	(1,634	)	 	(5	)	 	(3	)	 	(25	)	 	—	
 	 	(1,667	)	
Other cost of sales (a)	(312	)	 	(296	)	 	(21	)	 	—	
 	 	(924	)	 	21	
 	 	(1,532	)	 	(2,706	)	 	—	
 	 	(23	)	 	796	
 	 	(3,465	)	
Mark-to-market for economic hedging activities	62	
 	 	64	
 	 	(13	)	 	—	
 	 	50	
 	 	32	
 	 	195	
 	 	100	
 	 	—	
 	 	—	
 	 	49	
 	 	344	
 	
Contract and emission credit amortization	(16	)	 	16	
 	 	3	
 	 	—	
 	 	(5	)	 	—	
 	 	(2	)	 	—	
 	 	—	
 	 	(6	)	 	2	
 	 	(6	)	
Gross margin	$	794	
 	 	$	1,433	
 	 	$	235	
 	 	$	2	
 	 	$	174	
 	 	$	(12	)	 	$	2,626	
 	 	$	1,257	
 	 	$	332	
 	 	$	735	
 	 	$	75	
 	 	$	5,025	
 	
Less: Mark-to-market for economic hedging activities, net	(208	)	 	(175	)	 	(15	)	 	—	
 	 	50	
 	 	—	
 	 	(348	)	 	100	
 	 	—	
 	 	—	
 	 	—	
 	 	(248	)	
Less: Contract and emission credit amortization, net	(5	)	 	16	
 	 	3	
 	 	—	
 	 	(5	)	 	—	
 	 	9	
 	 	—	
 	 	(1	)	 	(57	)	 	2	
 	 	(47	)	
Economic gross margin	$	1,007	
 	 	$	1,592	
 	 	$	247	
 	 	$	2	
 	 	$	129	
 	 	$	(12	)	 	$	2,965	
 	 	$	1,157	
 	 	$	333	
 	 	$	792	
 	 	$	73	
 	 	$	5,320	
 	
Business Metrics	
MWh sold (thousands) (b)(c)	43,491	
 	 	35,681	
 	 	4,085	
 	 	 	 	 	 	 	 	 	 	 	 	2,968	
 	 	5,563	
 	 	 	 	 	
MWh generated (thousands)  (d)	39,516	
 	 	29,060	
 	 	3,265	
 	 	 	 	 	 	 	 	 	 	 	 	2,968	
 	 	6,828	
 	 	 	 	 	
Electricity sales volume — GWh	 	 	 	 	 	 	 	 	14,357	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Includes purchased energy, capacity and emissions credits	
(b) MWh sold excludes generation at facilities in the East,West and NRG Yield that generate revenue under capacity agreements.	
(c) Does not include thermal MWh of 61 thousand or MWt of 1,497 thousand for thermal sold by NRG Yield.	
(d) Does not include thermal MWh of 245 thousand or MWt of 1,497 thousand for thermal generated by NRG Yield.	

84

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Nine months ended September 30, 2015	
 	Generation	 	 	 	 	 	 	 	 	 	 	
(In millions)	Gulf Coast	 	East	 	West	 	International	 	Business Solutions	 	Eliminations	 	Subtotal	 	Retail Mass	 	Renewables	 	NRG Yield	 	Eliminations/Corporate	 	Total	
Energy revenue	$	2,015	
 	 	$	2,448	
 	 	$	196	
 	 	$	—	
 	 	$	—	
 	 	$	—	
 	 	$	4,659	
 	 	$	—	
 	 	$	281	
 	 	$	381	
 	 	$	(871	)	 	$	4,450	
 	
Capacity revenue	209	
 	 	1,009	
 	 	162	
 	 	—	
 	 	107	
 	 	—	
 	 	1,487	
 	 	—	
 	 	—	
 	 	252	
 	 	(10	)	 	1,729	
 	
Retail revenue	—	
 	 	—	
 	 	—	
 	 	—	
 	 	1,059	
 	 	—	
 	 	1,059	
 	 	4,308	
 	 	—	
 	 	—	
 	 	2	
 	 	5,369	
 	
Mark-to-market for economic hedging activities	31	
 	 	(174	)	 	10	
 	 	—	
 	 	4	
 	 	—	
 	 	(129	)	 	—	
 	 	(2	)	 	1	
 	 	(35	)	 	(165	)	
Contract amortization	12	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	12	
 	 	—	
 	 	—	
 	 	(40	)	 	—	
 	 	(28	)	
Other revenue	162	
 	 	61	
 	 	8	
 	 	3	
 	 	13	
 	 	(10	)	 	237	
 	 	—	
 	 	26	
 	 	135	
 	 	(90	)	 	308	
 	
Operating revenue	2,429	
 	 	3,344	
 	 	376	
 	 	3	
 	 	1,183	
 	 	(10	)	 	7,325	
 	 	4,308	
 	 	305	
 	 	729	
 	 	(1,004	)	 	11,663	
 	
Cost of fuel	(987	)	 	(1,217	)	 	(118	)	 	—	
 	 	—	
 	 	—	
 	 	(2,322	)	 	(6	)	 	(3	)	 	(34	)	 	7	
 	 	(2,358	)	
Other cost of sales (a)	(249	)	 	(384	)	 	(24	)	 	—	
 	 	(1,044	)	 	—	
 	 	(1,701	)	 	(3,130	)	 	(3	)	 	(24	)	 	934	
 	 	(3,924	)	
Mark-to-market for economic hedging activities	(11	)	 	(79	)	 	(15	)	 	—	
 	 	(87	)	 	—	
 	 	(192	)	 	34	
 	 	—	
 	 	—	
 	 	35	
 	 	(123	)	
Contract and emission credit amortization	(18	)	 	13	
 	 	—	
 	 	—	
 	 	(5	)	 	—	
 	 	(10	)	 	—	
 	 	—	
 	 	—	
 	 	(1	)	 	(11	)	
Gross margin	$	1,164	
 	 	$	1,677	
 	 	$	219	
 	 	$	3	
 	 	$	47	
 	 	$	(10	)	 	$	3,100	
 	 	$	1,206	
 	 	$	299	
 	 	$	671	
 	 	$	(29	)	 	$	5,247	
 	
Less: Mark-to-market for economic hedging activities, net	20	
 	 	(253	)	 	(5	)	 	—	
 	 	(83	)	 	—	
 	 	(321	)	 	34	
 	 	(2	)	 	1	
 	 	—	
 	 	(288	)	
Less: Contract and emission credit amortization, net	(6	)	 	13	
 	 	—	
 	 	—	
 	 	(5	)	 	—	
 	 	2	
 	 	—	
 	 	—	
 	 	(40	)	 	(1	)	 	(39	)	
Economic gross margin	$	1,150	
 	 	$	1,917	
 	 	$	224	
 	 	$	3	
 	 	$	135	
 	 	$	(10	)	 	$	3,419	
 	 	$	1,172	
 	 	$	301	
 	 	$	710	
 	 	$	(28	)	 	$	5,574	
 	
Business Metrics	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
MWh sold (thousands) (b)(c)	48,473	
 	 	47,525	
 	 	4,425	
 	 	 	 	 	 	 	 	 	 	 	 	2,790	
 	 	4,813	
 	 	 	 	 	
MWh generated (thousands)  (d)	46,214	
 	 	39,760	
 	 	3,194	
 	 	 	 	 	 	 	 	 	 	 	 	2,790	
 	 	6,631	
 	 	 	 	 	
Electricity sales volume — GWh	 	 	 	 	 	 	 	 	14,771	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(a) Includes purchased energy, capacity and emissions credits	
(b) MWh sold excludes generation at facilities in the East,West and NRG Yield that generate revenue under capacity agreements.	
(c) Does not include thermal MWh of 219 thousand or MWt of 1,519 thousand for thermal sold by NRG Yield.	
(d) Does not include thermal MWh of 219 thousand or MWt of 1,519 thousand for thermal generated by NRG Yield.	
The table below represents the weather metrics for the nine months ended September 30, 2016 and 2015:

 	Nine months ended September 30,	 	 	 	 	 	 	 	 	
Weather Metrics	Gulf Coast	 	East	 	West	 	 	 	 	 	 	 	 	
2016	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs (a)	2,605	
 	 	1,327	
 	 	869	
 	 	 	 	 	 	 	 	 	
HDDs (a)	984	
 	 	2,861	
 	 	1,231	
 	 	 	 	 	 	 	 	 	
2015	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs	2,585	
 	 	1,248	
 	 	984	
 	 	 	 	 	 	 	 	 	
HDDs	1,332	
 	 	3,451	
 	 	1,135	
 	 	 	 	 	 	 	 	 	
10 year average	 	 	 	 	 	 	 	 	 	 	 	 	 	
CDDs	2,656	
 	 	1,122	
 	 	804	
 	 	 	 	 	 	 	 	 	
HDDs	1,174	
 	 	3,101	
 	 	1,547	

(a)	National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.	

85

Generation gross margin and economic gross margin
The below tables present the changes in Generation gross margin and economic gross margin which include intercompany sales, during the nine months ended September 30, 2016, compared to the same period in 2015:

(In millions)	Gross Margin (increase/(decrease))	 	Economic Gross Margin (increase/(decrease))	
Gulf Coast region	$	(370	)	 	$	(143	)	
East region	(244	)	 	(325	)	
West region	16	
 	 	23	
 	
International	(1	)	 	(1	)	
Business Solutions	127	
 	 	(6	)	
 	$	(472	)	 	$	(452	)	

The decrease in Generation gross margin and economic gross margin was driven by:

Gulf Coast Region

 	(In millions)	
Lower gross margin primarily due to 20% lower coal generation in Texas, which was driven by lower prices, an increase in unplanned outages and timing of planned outages	$	(106	)	
Lower gross margin resulting from lower average realized energy prices due to a decline in natural gas prices	(60	)	
Higher gross margin from a 7% increase in nuclear generation driven by reduced planned outages	17	
 	
Higher gross margin, primarily in South Central, due to a 56% increase in PJM capacity volumes as more units cleared the 2015/2016 auction	12	
 	
Other	(6	)	
Decrease in economic gross margin	$	(143	)	
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(228	)	
Increase in contract and credit amortization	1	
 	
Decrease in gross margin	$	(370	)	

86

East Region

 	(In millions)	
Lower gross margin due to a 21% decrease in generation primarily driven by the environmental control work at Avon Lake and Powerton, fuel conversion projects at Joliet and Shawville facilities and the sale of the Seward, Aurora, Rockford and Shelby generating stations in 2016. In addition, there was a 6% decrease in generation as a result of prior year winter weather conditions and current year planned outages	$	(246	)	
Lower gross margin driven by a 14% decrease in capacity volumes due to plant deactivations and asset sales, partially offset by a 1% increase in PJM cleared auction capacity prices	(84	)	
Lower gross margin as a result of a 35% decrease in average realized energy prices due to a decline in natural gas prices in 2016	(82	)	
Lower gross margin driven primarily by a 4% decrease in New York and New England hedged capacity prices as well as the expiration of the Dunkirk RSS contract, and an 8% decrease in capacity volume related to the retirement of Huntley and certain units at the Astoria facility	(77	)	
Lower gross margin as a result of a decrease in ancillary services driven by lower generation in the current year	(22	)	
Higher gross margin due to the closure and financial settlement of hedge positions with a counterparty that would have otherwise been realized in the fourth quarter of 2016 and in the years 2017, 2018, and 2019	136	
 	
Changes in commercial optimization activities	29	
 	
Higher gross margin in 2016 due to a prior year lower cost of market adjustment for oil at Chalk Point and Bowline	11	
 	
Higher gross margin due to lower supply cost for servicing the load contracts	10	
 	
Decrease in economic gross margin	$	(325	)	
Increase in mark-to-market for economic hedging primarily due to reversals of previously recognized unrealized gains/losses on settled positions and unrealized gains/losses on open positions related to economic hedges	78	
 	
Increase in contract and credit amortization	3	
 	
Decrease in gross margin	$	(244	)	
West Region

 	(In millions)	
Gain on sale of excess emission credits	$	47	
 	
Lower gross margin due to an 11% decrease in capacity volumes, and a 5% decrease in capacity prices due to higher reserve margins driven by more competition in certain areas	(22	)	
Lower gross margin resulting from an 8% decrease in generation due to plant retirements and unfavorable market conditions, partially offset by higher availability at the Sunrise power plant, as well as Pittsburg generating station's merchant status due to toll expiration. There was also a 12% decrease in average realized energy prices	(5	)	
Other	3	
 	
Increase in economic gross margin	$	23	
 	
Decrease in mark-to-market for economic hedging activities driven by a decrease in the value of open positions	(10	)	
Increase in contract and credit amortization	3	
 	
Increase in gross margin	$	16	

87

Business Solutions

 	(In millions)	
Lower gross margin from the demand response business in 2016 due to lower commitments and pricing in PJM and New York markets	$	(4	)	
Lower gross margin in 2016 driven by a 10% decrease in customers	(2	)	
Decrease in economic gross margin	$	(6	)	
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	133	
 	
Increase in gross margin	$	127	

Retail Mass gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail Mass.

 	Nine months ended September 30,	
(In millions except otherwise noted)	2016	 	2015	
Retail Mass revenue	$	3,769	
 	 	$	4,198	
 	
Supply management revenue	99	
 	 	110	
 	
Operating revenue (a)	3,868	
 	 	4,308	
 	
Cost of sales (b)	(2,711	)	 	(3,136	)	
Mark-to-market for economic hedging activities	100	
 	 	34	
 	
Gross Margin	$	1,257	
 	 	$	1,206	
 	
Less: Mark-to-market for economic hedging activities, net	100	
 	 	34	
 	
Economic Gross Margin	$	1,157	
 	 	$	1,172	

Business Metrics	 	 	 	
Electricity sales volume — GWh - Gulf Coast	27,382	
 	 	27,534	
 	
Electricity sales volume — GWh - All other regions	5,264	
 	 	6,492	
 	
Average Retail Mass customer count (in thousands) (c)	2,770	
 	 	2,785	
 	
Ending Retail Mass customer count (in thousands) (c)	2,797	
 	 	2,762	

(a)	Includes intercompany sales of $2 million and $4 million in 2016 and 2015, respectively, representing sales from Retail Mass to the Gulf Coast region.	
 	 	
(b)	Includes intercompany purchases of $747 million and $877 million in 2016 and 2015.	
 	 	
(c)	Includes Retail Mass Recurring Customers and excludes Discrete Customers.	

Retail Mass gross margin increased $51 million and economic gross margin decreased $15 million for the nine months ended September 30, 2016, compared to the same period in 2015, due to:

 	(In millions)	
Lower gross margin from a reduction in load of 604,000 MWhs and unfavorable impacts from selling back excess supply due to milder weather conditions in 2016 as compared to 2015	$	(45	)	
Higher gross margin due to lower supply costs of $316 million or approximately $9 per MWh driven by a decrease in natural gas prices, partially offset by lower rates to customer of $281 million or approximately $8 per MWh	35	
 	
Lower gross margin due to lower volumes driven by lower average customer counts	(5	)	
Decrease in economic gross margin	$	(15	)	
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	66	
 	
Increase in gross margin	$	51	

88

Renewables gross margin and economic gross margin
Renewables gross margin increased $33 million and economic gross margin increased $32 million for the nine months ended September 30, 2016, compared to the same period in 2015, primarily driven by an 8% increase in generation at the Ivanpah solar plant and generation from the Guam solar plant that reached COD in the third quarter of 2015.
NRG Yield gross margin and economic gross margin
NRG Yield gross margin increased $64 million and economic gross margin increased $82 million for the nine months ended September 30, 2016, compared the same period in 2015, primarily driven by a 34% increase in volume generated at the Alta I-V wind projects, as well as due to an increase in price per MWh at the Alta X and XI wind projects as the PPAs began in January 2016, compared to merchant prices in 2015.

Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results increased by $40 million during the nine months ended September 30, 2016, compared to the same period in 2015.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:

 	Nine months ended September 30, 2016	
 	 	 	Generation	 	 	 	 	 	 	
 	Retail Mass	 	Gulf Coast	 	East	 	West	 	Business Solutions	 	Renewables	 	Elimination(a)	 	Total	
 	(In millions)	
Mark-to-market results in operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	—	
 	 	$	(260	)	 	$	(239	)	 	$	(4	)	 	$	(1	)	 	$	—	
 	 	$	(3	)	 	$	(507	)	
Reversal of acquired gain positions related to economic hedges	—	
 	 	—	
 	 	(37	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(37	)	
Net unrealized (losses)/gains on open positions related to economic hedges	—	
 	 	(10	)	 	37	
 	 	2	
 	 	1	
 	 	—	
 	 	(78	)	 	(48	)	
Total mark-to-market (losses)/gains in operating revenues	$	—	
 	 	$	(270	)	 	$	(239	)	 	$	(2	)	 	$	—	
 	 	$	—	
 	 	$	(81	)	 	$	(592	)	
Mark-to-market results in operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	128	
 	 	$	26	
 	 	$	80	
 	 	$	(1	)	 	$	89	
 	 	$	—	
 	 	$	3	
 	 	$	325	
 	
Reversal of acquired gain positions related to economic hedges	—	
 	 	—	
 	 	—	
 	 	(10	)	 	—	
 	 	—	
 	 	—	
 	 	(10	)	
Net unrealized (losses)/gains on open positions related to economic hedges	(28	)	 	36	
 	 	(16	)	 	(2	)	 	(39	)	 	—	
 	 	78	
 	 	29	
 	
Total mark-to-market gains/(losses) in operating costs and expenses	$	100	
 	 	$	62	
 	 	$	64	
 	 	$	(13	)	 	$	50	
 	 	$	—	
 	 	$	81	
 	 	$	344	

(a)	Represents the elimination of the intercompany activity between Retail Mass and Generation.	

89

 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Nine months ended September 30, 2015	
 	 	 	Generation	 	 	 	 	 	 	 	 	
 	Retail Mass	 	Gulf Coast	 	East	 	West	 	Business Solutions	 	Renewables	 	NRG Yield	 	Elimination(a)	 	Total	
 	(In millions)	
Mark-to-market results in operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	
 	 	$	(276	)	 	$	(225	)	 	$	5	
 	 	$	(1	)	 	$	(5	)	 	$	—	
 	 	$	(11	)	 	$	(513	)	
Reversal of acquired gain positions related to economic hedges	—	
 	 	—	
 	 	(62	)	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	—	
 	 	(62	)	
Net unrealized gains/(losses) on open positions related to economic hedges	—	
 	 	307	
 	 	113	
 	 	5	
 	 	5	
 	 	2	
 	 	2	
 	 	(24	)	 	410	
 	
Total mark-to-market gains/(losses) in operating revenues	$	—	
 	 	$	31	
 	 	$	(174	)	 	$	10	
 	 	$	4	
 	 	$	(3	)	 	$	2	
 	 	$	(35	)	 	$	(165	)	
Mark-to-market results in operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	200	
 	 	$	30	
 	 	$	14	
 	 	$	(1	)	 	$	80	
 	 	$	—	
 	 	$	—	
 	 	$	11	
 	 	$	334	
 	
Reversal of acquired gain positions related to economic hedges	(4	)	 	—	
 	 	—	
 	 	(15	)	 	(2	)	 	—	
 	 	—	
 	 	—	
 	 	(21	)	
Net unrealized (losses)/gains on open positions related to economic hedges	(162	)	 	(41	)	 	(93	)	 	1	
 	 	(165	)	 	—	
 	 	—	
 	 	24	
 	 	(436	)	
Total mark-to-market gains/(losses) in operating costs and expenses	$	34	
 	 	$	(11	)	 	$	(79	)	 	$	(15	)	 	$	(87	)	 	$	—	
 	 	$	—	
 	 	$	35	
 	 	$	(123	)	
 	 	
(a)	Represents the elimination of the intercompany activity between Retail Mass, Generation, and NRG Yield.	
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the nine months ended September 30, 2016, the $592 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts. The $344 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period.
For the nine months ended September 30, 2015, the $165 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts, largely offset by an increase in value of open positions as a result of decreases in ERCOT and PJM electricity and natural gas prices. The $123 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in ERCOT electricity and coal prices and the reversal of acquired contracts, largely offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 30, 2016, and 2015. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.

 	Nine months ended September 30,	
(In millions)	2016	 	2015	
Trading gains/(losses)	 	 	 	
Realized	$	67	
 	 	$	49	
 	
Unrealized	27	
 	 	(47	)	
Total trading gains	$	94	
 	 	$	2	
 	
In addition, trading activities reflect an increase in gross margin of $85 million, reflected in the Corporate segment, for the nine months ended September 30, 2016, as compared to the nine months ended September 30, 2015.

90

Operations and Maintenance Expense

 	Generation	 	Retail Mass	 	Renewables	 	NRG Yield	 	Corporate	 	 	 	
 	Gulf Coast	 	East	 	West	 	International	 	Business Solutions	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	(In millions)	 	 	 	 	 	 	
Nine months ended September 30, 2016	$	429	
 	 	$	713	
 	 	$	95	
 	 	$	1	
 	 	$	16	
 	 	$	164	
 	 	$	96	
 	 	$	118	
 	 	$	10	
 	 	$	1,642	
 	 	 	 	 	 	 	
Nine months ended September 30, 2015	488	
 	
 	781	
 	 	105	
 	 	1	
 	 	17	
 	 	165	
 	 	96	
 	 	120	
 	 	9	
 	 	1,782	
 	 	 	 	 	 	 	
Operations and maintenance expense decreased by $140 million for the nine months ended September 30, 2016, compared to the same period in 2015, due to the following:

 	(In millions)	
Decrease in Gulf Coast operations and maintenance expense primarily related to the timing of outages at the Limestone and STP facilities located in Texas	$	(63	)	
Decrease in operating costs due to the sale of the Seward and Shelby generating stations in 2016	(48	)	
Decrease in East operations and maintenance expense due primarily to deactivations of the Huntley, Dunkirk, and Astoria facilities coupled with a decrease in maintenance costs related to Canal, Waukegan, and Bowline	(46	)	
Decrease in West operations and maintenance expense primarily due to the retirement of El Segundo and lower maintenance costs across the region	(10	)	
Increase in East operating costs due to environmental work at Maryland ash sites	17	
 	
Increase in East variable operating costs driven by environmental control work at Avon Lake and Powerton and fuel conversion projects at the Joliet and Shawville facilities	14	
 	
Other	(4	)	
 	$	(140	)	
Other Cost of Operations

 	 	 	Retail Mass	 	Renewables	 	NRG Yield	 	Corporate	 	 	 	
 	Gulf Coast	 	East	 	West	 	Business Solutions	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
Nine months ended September 30, 2016	$	78	
 	 	$	71	
 	 	$	19	
 	 	$	4	
 	 	$	66	
 	 	$	14	
 	 	$	50	
 	 	$	—	
 	 	$	302	
 	 	 	 	 	 	 	
Nine months ended September 30, 2015	76	
 	 	99	
 	 	20	
 	 	14	
 	 	75	
 	 	16	
 	 	53	
 	 	—	
 	 	353	
 	 	 	 	 	 	 	
Other cost of operations, comprised of asset retirement expense, insurance expense and property and other tax expense, decreased by $51 million for the nine months ended September 30, 2016, compared to the same period in 2015, primarily due to a reduction in property tax for Chalk Point and Dickerson.
Depreciation and Amortization

 	 	 	Retail Mass	 	Renewables	 	NRG Yield	 	Corporate	 	 	 	
 	Gulf Coast	 	East	 	West	 	Business Solutions	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	
Nine months ended September 30, 2016	$	274	
 	 	$	156	
 	 	$	46	
 	 	$	7	
 	 	$	80	
 	 	$	142	
 	 	$	224	
 	 	$	50	
 	 	$	979	
 	 	 	 	 	 	 	
Nine months ended September 30, 2015	427	
 	 	208	
 	 	38	
 	 	8	
 	 	93	
 	 	135	
 	 	222	
 	 	42	
 	 	1,173	
 	 	 	 	 	 	 	
Depreciation and amortization expense decreased by $194 million for the nine months ended September 30, 2016, compared to the same period in 2015, primarily due to decreases in depreciation expense for facilities impaired in 2015, and the sale of the Seward and Shelby generating stations in 2016.

91

Impairment Losses
For the nine months ended September 30, 2016, the Company recorded impairment losses of $123 million, primarily due to the impairment of the Rockford stations and Mandalay and Ormond Beach operating units, as further described in Note 7, Impairments,  of this Form 10-Q.
Selling, Marketing, General and Administrative Expenses
Selling, marketing, general and administrative expenses are comprised of the following:

 	Generation	 	Retail Mass (b)	 	Renewables(c)	 	NRG Yield	 	Corporate(d)	 	 	 	
 	Gulf Coast	 	East	 	West	 	Business Solutions (a)	 	 	 	 	 	 	 	 	 	Total	 	 	 	 	 	 	
 	(In millions)	 	 	 	 	 	 	
Nine months ended September 30, 2016	$	98	
 	 	$	133	
 	 	$	24	
 	 	$	57	
 	 	$	304	
 	 	$	43	
 	 	$	10	
 	 	$	133	
 	 	$	802	
 	 	 	 	 	 	 	
Nine months ended September 30, 2015	114	
 	 	141	
 	 	30	
 	 	58	
 	 	306	
 	 	37	
 	 	9	
 	 	183	
 	 	878	
 	 	 	 	 	 	 	
(a) Includes selling and marketing expense of $31 million and $33 million for nine months ended September 30, 2016 and 2015.
(b) Includes selling and marketing expense of $199 million and $197 million for the nine months ended September 30, 2016 and 2015.
(c) Includes selling and marketing expense of $3 million and $5 million for the nine months ended September 30, 2016 and 2015.
(d) Includes selling and marketing expense of $56 million and $128 million for the nine months ended September 30, 2016 and 2015.

Selling, marketing, general and administrative expenses decreased by $76 million for the nine months ended September 30, 2016, compared to the same period in 2015, due primarily to a decrease in advertising and the continued focus on cost management in 2016, partially offset by an increase in cost to achieve expenses in 2016, which primarily reflects severance and employee costs based on the Company's recent strategy changes.
Development Activity Expenses
Development activity expenses decreased by $42 million for the nine months ended September 30, 2016, compared to the same period in 2015, due to the strategic move for a more focused development program primarily related to Renewables and the sale of EVgo in 2016.
Gain on Sale of Assets
During the nine months ended September 30, 2016, the Company recognized a $215 million gain on sale of assets primarily related to the sale of the Aurora generating station, the sale of real property at the Potrero location, and the sale of the 100% interest in the Shelby generating station. The Company also sold a majority interest in its EVgo business to Vision Ridge Partners, which resulted in a loss on sale, as described in Note 3,  Business Acquisitions and Dispositions,
Impairment Losses on Investments
For the nine months ended September 30, 2016, the Company recorded other-than-temporary impairment losses of $147 million, which is primarily due to its 50% interest in Petra Nova Parish Holdings, as further described in Note 7,  Impairments, of this Form 10-Q.
Loss on Debt Extinguishment
A loss on debt extinguishment of $119 million was recorded for the nine months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

92

Interest Expense
NRG's interest expense decreased by $14 million for the nine months ended September 30, 2016, compared to the same period in 2015 due to the following:

 	(In millions)	
Decrease due to the repurchases of Senior Notes at the end of 2015 and first three quarters of 2016	$	(38	)	
Decrease due to the redemption of outstanding bonds related to NRG Peakers Finance Company	(8	)	
Decrease due to the termination of Alta X and XI term loans and the related interest rate swaps in 2015	(6	)	
Increase in derivative interest expense from changes in fair value of interest rate swaps	28	
 	
Increase due to the issuance of NRG Yield Inc. 3.25% Convertible Senior Notes due 2020 and NRG Yield Operating LLC Revolving Credit Facility issued in 2015	7	
 	
Increase due to $200 million of debt issued by CVSR Holdco in August 2016	2	
 	
Other	1	
 	
 	$	(14	)	
Income Tax Expense/(Benefit)
For the nine months ended September 30, 2016, NRG recorded an income tax expense of $95 million on pre-tax income of $259 million. For the same period in 2015, NRG recorded an income tax benefit of $43 million on a pre-tax loss of $121 million. The effective tax rate was 36.7% and 35.5% for the nine months ended September 30, 2016, and 2015, respectively.
For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state tax expense and amortization of indefinite lived assets, partially offset by the change in valuation allowance.
For the nine months ended September 30, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of production tax credits generated from our wind assets, partially offset by tax expense attributable to consolidated partnerships.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
For the nine months ended September 30, 2016, and 2015, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, partially offset by NRG Yield, Inc.'s share of net income.

Liquidity and Capital Resources
Liquidity Position
As of September 30, 2016, and December 31, 2015, NRG's liquidity, excluding collateral received, was approximately $4.3 billion and $3.3 billion, respectively, comprised of the following:

(In millions)	September 30, 2016	 	December 31, 2015	
Cash and cash equivalents:	 	 	 	
NRG excluding NRG Yield and GenOn	$	1,017	
 	 	$	742	
 	
NRG Yield and subsidiaries	200	
 	 	111	
 	
GenOn and subsidiaries	1,218	
 	 	665	
 	
Restricted cash - operating	145	
 	 	127	
 	
Restricted cash - reserves (a)	335	
 	 	287	
 	
Total	2,915	
 	 	1,932	
 	
Total credit facility availability	1,374	
 	 	1,373	
 	
Total liquidity, excluding collateral received	$	4,289	
 	 	$	3,305	
 	
(a)Includes reserves primarily for debt service, performance obligations, and capital expenditures
For the nine months ended September 30, 2016, total liquidity, excluding collateral funds deposited by counterparties, increased by $1 billion. Changes in cash and cash equivalents balances are further discussed hereinafter under the heading  Cash Flow Discussion . Cash and cash equivalents at September 30, 2016, were predominantly held in money market mutual funds invested in treasury securities, treasury repurchase agreements or government agency debt.

93

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments with the exception of commitments related to GenOn as further described below. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.
Restricted Payments Tests
Of the $2.4 billion of cash and cash equivalents of the Company as of September 30, 2016, $483 million and $110 million were held by GenOn Mid-Atlantic and REMA, respectively. The ability of certain of GenOn’s and GenOn Americas Generation’s subsidiaries to pay dividends and make distributions is restricted under the terms of certain agreements, including the GenOn Mid-Atlantic and REMA operating leases.  Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless:  (a) they satisfy the fixed charge coverage ratio for the most recently ended period of four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing.  In addition, prior to making a dividend or other restricted payment, REMA must be in compliance with the requirement to provide credit support to the owner lessors securing its obligation to pay scheduled rent under its leases. Based on GenOn Mid-Atlantic’s and REMA’s most recent calculations of these tests, GenOn Mid-Atlantic and REMA did not satisfy the restricted payments tests. As a result, as of September 30, 2016, GenOn Mid-Atlantic and REMA could not make distributions of cash and certain other restricted payments. Each of GenOn Mid-Atlantic and REMA may recalculate its fixed charge coverage ratios from time to time and, subject to compliance with the restricted payments test described above, make dividends or other restricted payments.
To the extent GenOn Mid-Atlantic or REMA are able to pay dividends to GenOn, the GenOn Senior Notes due 2018 and 2020 and the related indentures also restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At September 30, 2016, GenOn did not meet the consolidated debt ratio component of the restricted payments test.
GenOn Liquidity
As disclosed in Note 8, Debt and Capital Leases, $703 million of GenOn's Senior Notes outstanding are current within the GenOn consolidated balance sheet and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity to repay the senior notes due in June 2017. As a result of these factors, there is no assurance GenOn will continue as a going concern.
GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the senior notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During the second quarter of 2016, GenOn appointed two independent directors as part of this process. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.
Credit Ratings
On March 3, 2016 and March 21, 2016, respectively, S&P and Moody's reaffirmed the corporate credit ratings on NRG Energy, Inc.
On October 7, 2016, GenOn's corporate credit rating was lowered by Moody's from Caa2 to Caa3 and its probability of default rating was lowered from Caa2-PD to Caa3-PD. In addition, Moody's also lowered the ratings of REMA and GenOn Mid-Atlantic's pass through certificates to Caa1 from B2.
This is an update from March 21, 2016, at which time GenOn's corporate credit rating was lowered from B3 to Caa2. At that time, Moody's also lowered the issue level ratings on the GenOn senior notes from B3 to Caa2 and the GenOn America's Generation senior notes from Caa1 to Caa2.
On May 24, 2016, S&P lowered its corporate credit ratings on GenOn to CCC from CCC+. The ratings outlook for GenOn, GenOn Americas Generation, GenOn Mid-Atlantic and REMA is negative. S&P also lowered the issue ratings on the GenOn senior notes to CCC+ from B-, the GenOn Americas Generation senior notes to CCC from CCC+, and the pass-through certificates at REMA to B- from B. S&P upgraded the rating on the pass-through certificates at GenOn Mid-Atlantic to B- from CCC+.

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On August 15, 2016, S&P lowered its corporate credit ratings on NRG Yield, Inc. and the NRG Yield Operating 2024 Senior Notes to BB from BB+. The ratings outlook is stable.
The following table summarizes the Company's credit ratings as of September 30, 2016:

 	S&P	 	Moody's	
NRG Energy, Inc. 	BB- Stable	 	Ba3 Stable	
7.625% Senior Notes, due 2018	BB-	 	B1	
8.25% Senior Notes, due 2020	BB-	 	B1	
7.875% Senior Notes, due 2021	BB-	 	B1	
6.25% Senior Notes, due 2022	BB-	 	B1	
6.625% Senior Notes, due 2023	BB-	 	B1	
6.25% Senior Notes, due 2024	BB-	 	B1	
7.25% Senior Notes, due 2026	BB-	 	B1	
6.625% Senior Notes, due 2027	BB-	 	B1	
Term Loan Facility, due 2023	BB+	 	Baa3	
GenOn 7.875% Senior Notes, due 2017	CCC+	 	Caa2	
GenOn 9.500% Senior Notes, due 2018	CCC+	 	Caa2	
GenOn 9.875% Senior Notes, due 2020	CCC+	 	Caa2	
GenOn Americas Generation 8.500% Senior Notes, due 2021	CCC	 	Caa2	
GenOn Americas Generation 9.125% Senior Notes, due 2031	CCC	 	Caa2	
NRG Yield, Inc.	BB	 	Ba2	
5.375% NRG Yield Operating LLC Senior Notes, due 2024	BB	 	Ba2	
5.00% NRG Yield Operating LLC Senior Notes, due 2026	BB	 	Ba2	

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Sources of Liquidity
The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand, cash flows from operations and cash proceeds from future sales of assets, including sales to NRG Yield, Inc. As described in Note 8,  Debt and Capital Leases , to this Form 10-Q and Note 12, Debt and Capital Leases , to the Company's 2015 Form 10-K, the Company's financing arrangements consist mainly of the 2016 Senior Credit Facility, the Senior Notes, the GenOn Senior Notes, the GenOn Americas Generation Senior Notes, the NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the NRG Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility, and project-related financings.
Sale of CVSR to NRG Yield, Inc. and CVSR Financing Arrangement
On July 15, 2016, CVSR Holdco LLC issued $200 million of senior secured notes that bear interest at 4.68% and mature on March 31, 2037 .  The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and to NRG Yield Operating LLC, the owners of CVSR Holdco LLC, based on their pro-rata ownership. NRG Yield Operating LLC utilized its net proceeds of $97.5 million to reduce the outstanding balance of its revolving credit facility. NRG expects to utilize its net proceeds in connection with the 2016 Capital Allocation Program. On September 1, 2016, the Company sold its remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, to NRG Yield, Inc. for total cash consideration of $78.5 million plus an immaterial working capital adjustment. NRG Yield, Inc. also assumed $496 million of non-recourse debt as of the closing date.
Thermal Financing
On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Yield, Inc. received proceeds of $125 million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility for the anticipated issuance of an additional $70 million of notes. The Series D Notes are, and the additional notes, if issued, will be secured by substantially all of the assets of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries. NRG Energy Center Minneapolis LLC distributed the proceeds of the Series D Notes to NRG Thermal LLC, who in turn distributed the proceeds to NRG Yield Operating LLC to be utilized for general corporate purposes, including potential acquisitions.
Issuance of 2027 Senior Notes
On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and to reduce the balance of the Company's 7.875% senior notes due 2021.
Capistrano Refinancing
In July 2016, Cedro Hill, Broken Bow and Crofton Bluffs, subsidiaries of Capistrano Wind Partners, each amended their respective credit facilities to increase borrowings to a total of $312 million and to lower their respective interest rates.  The net proceeds of $87 million were distributed to Capistrano Wind Partners and subsequently distributed to the holders of the Class B preferred equity interests of Capistrano Wind Partners.
EVgo
On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California.

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Issuance of 2026 Senior Notes
On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026. The proceeds from the issuance of the 2026 Senior Notes were utilized to redeem a portion of the Senior Notes as discussed in  Uses of Liquidity .
Midwest Generation
On April 7, 2016, Midwest Generation, LLC, or MWG, entered into an agreement to sell certain quantities of unforced capacity that has cleared various PJM Reliability Pricing Model auctions to a trading counterparty for net proceeds of $253 million.  MWG will continue to operate the applicable generation facilities and remains responsible for performance penalties and is eligible for performance bonus payments, if any. Accordingly, MWG will continue to account for all revenues and costs as before; however, the proceeds will be recorded as a financing obligation while capacity payments by PJM to the counterparty will be reflected as debt amortization and interest expense through the end of the 2018/19 delivery year.  MWG will amortize the upfront discount to interest expense, at an effective interest rate of 4.39%, over the term of the arrangement, through June 2019.
Asset Dispositions
During the nine months ended September 30, 2016, the Company received proceeds of $118 million related to the sale of its Seward and Shelby generating stations, proceeds of $56 million related to the sale of its Rockford generating stations, proceeds of $369 million related to the sale of GenOn's Aurora generating station and proceeds of $74 million related to the sale of the Potrero site.
Cash Grants
As of September 30, 2016, the Company had a net renewable energy grant receivable of $33 million, net of sequestration.
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired through GenOn and EME (including Midwest Generation), assets held by NRG Yield, Inc., and NRG's assets that have project-level financing. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have claim under the first lien program. The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, excluding GenOn and Midwest Generation's coal capacity, and 10% of its other assets, excluding GenOn's other assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of September 30, 2016, all hedges under the first liens were in-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of September 30, 2016:

Equivalent Net Sales Secured by First Lien Structure (a)	2016	 	2017	 	2018	 	2019	 	2020	
In MW	2,276	
 	 	2,303	
 	 	478	
 	 	—	
 	 	—	
 	
As a percentage of total net coal and nuclear capacity (b)	39	%	 	40	%	 	8	%	 	—	%	 	—	%	
 	 	
(a)	Equivalent net sales include natural gas swaps converted using a weighted average heat rate by region.	
 	 	
(b)	Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the GenOn and EME (Midwest Generation) acquisitions, assets in NRG Yield, Inc. and NRG's assets that have project level financing.	

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Uses of Liquidity
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) allocations in connection with the Capital Allocation Program including acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders.
Commercial Operations
NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of September 30, 2016, commercial operations had total cash collateral outstanding of $337 million, and $824 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of September 30, 2016, total collateral held from counterparties was $16 million in cash and $44 million in letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG's credit ratings and general perception of its creditworthiness.

98

Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments for the nine months ended September 30, 2016, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2016. 

 	Maintenance	 	Environmental	 	Growth Investments	 	Total	
 	(In millions)	
Generation	 	 	 	 	 	 	 	
Gulf Coast	$	130	
 	 	$	7	
 	 	$	5	
 	 	$	142	
 	
East	107	
 	 	230	
 	 	99	
 	 	436	
 	
West	2	
 	 	—	
 	 	25	
 	 	27	
 	
Business Solutions	6	
 	 	—	
 	 	1	
 	 	7	
 	
Retail Mass	11	
 	 	—	
 	 	—	
 	 	11	
 	
Renewables	12	
 	 	—	
 	 	159	
 	 	171	
 	
NRG Yield	12	
 	 	—	
 	 	4	
 	 	16	
 	
Corporate (b)	25	
 	 	—	
 	 	63	
 	 	88	
 	
Total cash capital expenditures for the nine months ended September 30, 2016	305	
 	 	237	
 	 	356	
 	 	898	
 	
     Funding from debt financing, net of fees	—	
 	 	—	
 	 	(26	)	 	(26	)	
     Funding from third party equity partners and cash grants	—	
 	 	—	
 	 	(111	)	 	(111	)	
     Other investments (a)	—	
 	 	—	
 	 	75	
 	 	75	
 	
Total capital expenditures and investments, net of financings	305	
 	 	237	
 	 	294	
 	 	836	

Estimated capital expenditures for the remainder of 2016	139	
 	 	46	
 	 	1,210	
 	 	1,395	
 	
     Funding from debt financing, net of fees	—	
 	 	—	
 	 	(711	)	 	(711	)	
     Funding from third party equity partners and cash grants	—	
 	 	—	
 	 	(187	)	 	(187	)	
     Other investments (a)	—	
 	 	—	
 	 	21	
 	 	21	
 	
NRG estimated capital expenditures for the remainder of 2016, net of financings	$	139	
 	 	$	46	
 	 	$	333	
 	 	$	518	

(a)	Other investments include restricted cash activity.	
 	 	
(b)	Includes residential solar.	
 	 	
•	Environmental capital expenditures — For the nine months ended September 30, 2016, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS as well as controls to satisfy MATS at the Avon Lake facility.	
 	 	
•	Growth Investments capital expenditures — For the nine months ended September 30, 2016, the Company's growth investment capital expenditures included $197 million for solar projects, $99 million for fuel conversions, $30 million for repowering projects, $4 million for thermal projects and $26 million for the Company's other growth projects.	
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2016 through 2020 required to comply with environmental laws will be approximately $328 million which includes $76 million for GenOn and $234 million for Midwest Generation. These costs, the majority of which will be expended by the end of 2016, are primarily associated with (i) DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS and (ii) MATS compliance at the Avon Lake facility.
In connection with the acquisition of EME, on April 1, 2014, NRG committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to comply with environmental regulations, of which $23 million was remaining as of September 30, 2016. The expected costs of these projects are included in the environmental capital expenditures detailed above.

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2016 Capital Allocation Program
The Company's plan to allocate capital during 2016 is as follows:
 	 	
•	Debt Reduction. The Company allocated a majority of NRG's capital available for allocation during 2016 to additional debt repurchases in order to meet the Company's goal of prudent balance sheet management in a low commodity price environment. Since the third quarter of 2015, the Company has retired $1 billion of corporate debt, generating savings of $78 million in annualized interest.	

•	Growth Investments.  The Company intends to use a portion of capital available for allocation during 2016 primarily to complete its fuel repowerings, conversions and renewable investments.	

•	Common Stock Dividends.  On February 29, 2016, the Company announced a reduction in its common stock dividend to $0.12 per share on an annualized basis.  The decision to reduce the common stock dividend is a proactive measure taken by the Company in order to reallocate capital in accordance with the priorities set forth in this section.	

The Company will continue to monitor market conditions in light of the Company’s 2016 Capital Allocation Program to determine if adjustments are necessary in the future. 
Debt Reduction
The following table lists the repurchases of senior notes in 2016.

 	Principal Repurchased	 	Cash Paid (a)                          	 	Average Early Redemption Percentage	
Amount in millions, except rates	 	 	 	 	 	
7.625% senior notes due 2018	$	455	
 	 	$	502	
 	 	107.95	%	
8.250% senior notes due 2020	1,058	
 	 	1,129	
 	 	103.12	%	
7.875% senior notes due 2021	729	
 	 	771	
 	 	104.02	%	
6.250% senior notes due 2022	108	
 	 	105	
 	 	94.73	%	
6.625% senior notes due 2023	67	
 	 	64	
 	 	94.13	%	
6.250% senior notes due 2024	171	
 	 	163	
 	 	94.52	%	
Total at September 30, 2016	$	2,588	
 	 	$	2,734	
 	 	 	
7.625% senior notes due 2018 (b)	186	
 	 	204	
 	 	107.75	%	
7.875% senior notes due 2021 (b)	193	
 	 	207	
 	 	103.94	%	
Total at November 4, 2016	$	2,967	
 	 	$	3,145	
 	 	 	
(a) Includes payment for accrued interest
(b) Redemptions financed by cash on hand

Preferred Stock
On May 24, 2016, the Company entered an agreement with Credit Suisse Group to    repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The Company anticipates the transaction to generate approximately $10 million in annual dividend savings.
Dividends
The following table lists the dividends paid during the nine months ended September 30, 2016:

 	Third Quarter 2016	 	Second Quarter 2016	 	First Quarter 2016	
Dividends per Common Share	$	0.030	
 	 	$	0.030	
 	 	$	0.145	
 	
On October 19, 2016, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable November 15, 2016, to stockholders of record as of November 1, 2016 representing $0.12 on an annualized basis.

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The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.
UPMC Thermal Project
On October 31, 2016, NRG Business Services LLC, a subsidiary of the Company, and NRG Energy Center Pittsburgh LLC, or NECP, a subsidiary of NRG Yield, Inc., entered into a EPC agreement for the construction of a 73 MWt district energy system for NECP to provide 150 kpph of steam, 6,750 tons of chilled water and 7.5 MW of emergency backup power service to UPMC. The initial term of the energy services agreement (under fixed capacity payments) with UPMC Mercy will be for a period of twenty years from the service commencement date.  Pursuant to the terms of the EPC agreement, NECP shall pay NRG Business Services LLC $79 million, subject to adjustment based upon certain conditions in the EPC agreement, upon substantial completion of the project. The project is expected to reach COD in the first quarter of 2018.
SunEdison Utility-Scale Solar and Wind Acquisition
On September 15, 2016, the Company entered into an agreement with SunEdison to acquire (i) an equity interest in a tax-equity portfolio of 530 MW mechanically-complete solar assets of which NRG’s net interest based on cash to be distributed will be 265 MW, and an additional 937 MW of solar and wind assets in development, (ii) a 154 MW construction-ready solar facility in Texas and (iii) a 182 MW portfolio of construction-ready and development solar assets in Hawaii.  The acquisition of the portfolio of solar assets in Hawaii was completed on October 7, 2016 for upfront cash consideration of $2 million and the acquisition of the 530 MW tax equity portfolio and the 937 MW development assets was completed on November 2, 2016 for upfront cash consideration of $111 million. The Company expects to pay total upfront cash consideration for the three acquisitions of $129 million, with an estimated $59 million in additional payments contingent upon future development milestones.
SunEdison Solar Distributed Generation Acquisition
On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $68 million, subject to post closing adjustments.  The Company expects to sell these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc.
Fuel Repowerings and Conversions
The table below lists the Company's currently projected repowering and conversion projects. With respect to facilities that are currently operating, the timing of the projects listed below could adversely impact the Company's operating revenues, gross margin and other operating costs during the period prior to the targeted COD.

Facility	 	Net Generation Capacity (MW)	 	Project Type	 	Fuel Type	 	Targeted COD	
Fuel Conversions(a)	 	 	 	 	 	 	 	 	
Joliet Units 6, 7 and 8(b)	 	1,326	
 	 	Environmental	 	Natural Gas	 	Q4 2016	
Shawville Units 1, 2, 3 and 4	 	597	
 	 	Growth	 	Natural Gas	 	Q4 2016	
Total	 	1,923	
 	 	 	 	 	 	 	
Repowerings	 	 	 	 	 	 	 	 	
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT (c)	 	527	
 	 	Growth	 	Natural Gas	 	Q4 2018	
Puente (formerly Mandalay) Units 1 and 2(c)	 	262	
 	 	Growth	 	Natural Gas	 	Q2 2020	
Bacliff (formerly Cielo Lindo/PH Robinson) Peakers 1-6	 	360	
 	 	Growth	 	Natural Gas	 	Q1 2017	
Total	 	1,149	

Total Fuel Repowerings and Conversions	 	3,072	
 	 	 	 	 	 	 	
    (a) Does not include the natural gas conversions of (i) Dunkirk Units 2, 3 and 4, which are on hold pending the outcome of outstanding litigation; and (ii) New Castle Units 3, 4 and 5, which were completed in the second quarter of 2016.    
(b) The Company has incurred and will incur environmental capital expenditures to switch to gas to satisfy MATS. Joliet Units 6, 7 & 8 are in commercial service using natural gas; the balance of plant work is being completed for full load operation of Unit 6.
(c) Projects are subject to applicable regulatory approvals and permits.

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Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative nine month periods:

 	Nine months ended September 30,	 	 	
 	2016	 	2015	 	Change	
 	(In millions)	
Net cash provided by operating activities	$	1,733	
 	 	$	1,392	
 	 	$	341	
 	
Net cash used in investing activities	(321	)	 	(1,232	)	 	911	
 	
Net cash used by financing activities	(489	)	 	(26	)	 	(463	)	
Net Cash Provided By Operating Activities
Changes to net cash provided by operating activities were driven by:

 	(In millions)	
Change in cash collateral in support of risk management activities	$	411	
 	
Decrease in inventory primarily related to plant fuel conversions at Shawville, Joliet, New Castle and Unit 2 at the Big Cajun II facility and deactivations of Huntley and Dunkirk	137	
 	
Other changes in working capital driven by various timing differences	34	
 	
Increase in prepaid expense primarily related to timing of property tax and insurance payments that occurred in the first half of the year	(58	)	
Decrease in operating income adjusted for non-cash items	(55	)	
Decrease in accounts payable primarily related to lower operations and maintenance expense in 2016	(50	)	
Increase in accounts receivable due to timing of receipts	(48	)	
Decrease in accrued interest primarily driven by redemption of Senior Notes in late 2015 and 2016	(30	)	
 	$	341	
 	
Net Cash Provided In Investing Activities
Changes to net cash used in investing activities were driven by:

 	(In millions)	
Proceeds from the sale of assets related to the majority interest sale of EVgo, the sale of real property at the Potrero generating station and the sale of the Aurora, Seward and Shelby generating stations in 2016	$	635	
 	
Decrease in investments in unconsolidated affiliates in 2016 compared to 2015, primarily related to the 25% investment in Desert Sunlight of $285 million, as well as, Petra Nova and Altenex in 2015	334	
 	
Insurance proceeds primarily related to the Cottonwood generation station outage in 2016	27	
 	
Decrease in cash paid for acquisitions in 2016 compared to 2015, primarily related to the Spring Canyon acquisition in 2015	13	
 	
Increase in notes receivable and other	11	
 	
Decrease in cash grants received as the final Ivanpah cash grant amount was received in 2015 after resolution of all open inquiries	(51	)	
Decrease in restricted cash primarily related to the Agua Caliente and CVSR projects	(26	)	
Net decrease in nuclear decommissioning trust fund activity	(23	)	
Increase in capital expenditures, primarily related to environmental projects at Powerton and Joliet	(9	)	
 	$	911	

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Net Cash Used By Financing Activities
Changes to net cash used by financing activities were driven by:

 	(In millions)	
Decrease in cash contributions from noncontrolling interest in 2016, primarily related to the NRG Yield, Inc public offering in 2015 which had proceeds of $600 million	$	(778	)	
Repurchase of preferred stock in 2016	(226	)	
Increase in debt issuance costs primarily due to the refinancing of the senior credit facility and the issuance of the 2026 and 2027 Senior Notes	(56	)	
Repurchases of treasury stock in 2015	353	
 	
Net decrease in borrowings, offset by debt payments, which includes debt repurchases in 2016	155	
 	
Decrease in payment of dividends which reflects the reduction to the annualized dividend rate in 2016 from $0.58/share to $0.12/share	86	
 	
Other	3	
 	
 	$	(463	)	

103

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the nine months ended September 30, 2016, the Company had a total domestic pre-tax book income of $248 million and foreign pre-tax book income of $11 million. As of December 31, 2015, the Company has cumulative domestic Federal NOL carryforwards of $4.0 billion which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $202 million, which do not have an expiration date.
In addition to these amounts, the Company has $40 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $40 million in 2016.
The Company has recorded a non-current tax liability of $44 million until final resolution with the related taxing authority. The $44 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2009. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments — As of September 30, 2016, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 9,  Variable Interest Entities, or VIEs,  to this Form 10-Q.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $638 million as of September 30, 2016. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16,  Investments Accounted for by the Equity Method and Variable Interest Entities,  to the Company's 2015 Form 10-K.
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2015 Form 10-K. See also Note 8,  Debt and Capital Leases , and Note 14,  Commitments and Contingencies , to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the nine months ended September 30, 2016.

104

Fair Value of Derivative Instruments
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with,  Fair Value of Derivative Instruments  in Item 7 —  Management's Discussion and Analysis of Financial Condition and Results of Operations,  of the Company's 2015 Form 10‑K.
The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820,  Fair Value Measurements and Disclosures , or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at September 30, 2016, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2016.

Derivative Activity Gains/(Losses)	(In millions)	
Fair value of contracts as of December 31, 2015	$	6	
 	
Contracts realized or otherwise settled during the period	(180	)	
Changes in fair value	(50	)	
Fair Value of Contracts as of September 30, 2016	$	(224	)	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Fair Value of Contracts as of September 30, 2016	
 	Maturity	
Fair value hierarchy Gains/(Losses)	1 Year or Less	 	Greater than 1 Year to 3 Years	 	Greater than 3 Years to 5 Years	 	Greater than 5 Years	 	Total Fair
Value	
 	(In millions)	
Level 1	$	15	
 	 	$	(67	)	 	$	(15	)	 	$	—	
 	 	$	(67	)	
Level 2	(15	)	 	(47	)	 	(38	)	 	(31	)	 	(131	)	
Level 3	(5	)	 	(10	)	 	(7	)	 	(4	)	 	(26	)	
Total	$	(5	)	 	$	(124	)	 	$	(60	)	 	$	(35	)	 	$	(224	)	
The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3   —  Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk , to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of September 30, 2016, NRG's net derivative liability was $224 million, a decrease to total fair value of $230 million as compared to December 31, 2015. This decrease was driven by the roll-off of trades that settled during the period and losses in fair value.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $121 million in the net value of derivatives as of September 30, 2016. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately $88 million in the net value of derivatives as of September 30, 2016.

105

Critical Accounting Policies and Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets, goodwill and other intangible assets, and contingencies.
The Company performs its annual test of goodwill impairment during the fourth quarter. The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company notes that if natural gas prices continue to decrease, this could have a negative impact on the fair value of the reporting units that have goodwill balances and recovery of long-lived assets. Additionally, continued decreases in natural gas prices could result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. Accordingly, if these decreases continue, it is possible that the Company's goodwill or long-lived assets will be impaired.

106

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk,  of the Company's 2015 Form 10-K.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the nine months ending September 30, 2016, and 2015:

(In millions)	2016	 	2015	
VaR as of September 30,	$	40	
 	 	$	36	
 	
Three months ended September 30,	 	 	 	
Average	$	59	
 	 	$	39	
 	
Maximum	72	
 	 	44	
 	
Minimum	40	
 	 	34	
 	
Nine months ended September 30,	 	 	 	
Average	$	58	
 	 	$	42	
 	
Maximum	72	
 	 	54	
 	
Minimum	40	
 	 	34	
 	
In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of September 30, 2016, for the entire term of these instruments entered into for both asset management and trading was $43 million, primarily driven by asset-backed transactions.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
The Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Note 12,  Debt and Capital Leases,  of the Company's 2015 Form 10-K for more information on the Company's interest rate swaps.
If all of the above swaps had been discontinued on September 30, 2016, the Company would have owed the counterparties $163 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of September 30, 2016, a 1% change in variable interest rates would result in a $13 million change in interest expense on a rolling twelve month basis.

107

As of September 30, 2016, the fair value and related carrying value of the Company's debt was $18.9 billion and $19.4 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $1.6 billion.
Liquidity Risk
Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $179 million as of September 30, 2016, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $216 million as of September 30, 2016. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 30, 2016.
Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 4, Fair Value of Financial Instruments , to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 6,  Accounting for Derivative Instruments and Hedging Activities , to this Form 10-Q for discussion regarding credit risk contingent features.
Currency Exchange Risk
NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

108

ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure ControlsandProcedures
Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.
Changes in Internal Control over Financial Reporting
There were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the third quarter of 2016 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

109

PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through September 30, 2016, see Note 14, Commitments and Contingencies , to this Form 10-Q.
ITEM 1A — RISK FACTORS
Information regarding risk factors appears in Part I, Item 1A, RiskFactors Related to NRG Energy, Inc., in the Company's 2015 Form 10-K. Except as presented below, there have been no material changes in the Company's risk factors since those reported in its 2015 Form 10‑K.
There is no assurance GenOn will continue as a going concern.  GenOn’s inability to continue as a going concern could have a material impact on the Company.

As disclosed in Note 8, Debt and Capital Leases, to this Form 10-Q, as of September 30, 2016, $703 million of GenOn's Senior Notes outstanding are current within the GenOn consolidated balance sheet and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity exclusive of cash subject to the restrictions under the GenOn Mid-Atlantic and REMA operating leases to repay the senior notes due in June 2017. As a result of these factors, there is no assurance GenOn will continue as a going concern.
As of September 30, 2016, GenOn has cash and cash equivalents of $1.2 billion, of which $483 million and $110 million is held by GenOn Mid-Atlantic and REMA, respectively. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period for four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. Additionally, REMA must be in compliance with the requirement to provide credit support to the owner lessors securing its obligation to pay scheduled rent under its lease. As a result, GenOn Mid-Atlantic has not been able to make distributions of cash and certain other restricted payments since the quarter ended March 31, 2014 which was the last quarterly period for which GenOn Mid-Atlantic satisfied the conditions under its operating agreement. REMA has not satisfied the conditions under its operating agreement to make distributions of cash and certain other restricted payments since GenOn was acquired by NRG in December 2012.
The Company, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between the Company and GenOn and NRG Americas.

GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the senior notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During the second quarter of 2016, GenOn appointed two independent directors as part of this process.

The Company cannot assure you that GenOn’s inability to continue as a going concern will not have a material impact on the Company's statement of operations, cash flows and financial position including, among other things, if GenOn were to file for bankruptcy protection.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.

110

ITEM 5 — OTHER INFORMATION
None.

111

ITEM 6 — EXHIBITS

Number	 	Description	 	Method of Filing	
31.1	 	Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.	 	Filed herewith.	
31.2	 	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	 	Filed herewith.	
31.3	 	Rule 13a-14(a)/15d-14(a) certification of David Callen.	 	Filed herewith.	
32	 	Section 1350 Certification.	 	Furnished herewith.	
101 INS	 	XBRL Instance Document.	 	Filed herewith.	
101 SCH	 	XBRL Taxonomy Extension Schema.	 	Filed herewith.	
101 CAL	 	XBRL Taxonomy Extension Calculation Linkbase.	 	Filed herewith.	
101 DEF	 	XBRL Taxonomy Extension Definition Linkbase.	 	Filed herewith.	
101 LAB	 	XBRL Taxonomy Extension Label Linkbase.	 	Filed herewith.	
101 PRE	 	XBRL Taxonomy Extension Presentation Linkbase.	 	Filed herewith.	

112

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.

 	NRG ENERGY, INC.
(Registrant) 	 	
 	 	 	
 	/s/ MAURICIO GUTIERREZ 	 	
 	Mauricio Gutierrez	 	
 	Chief Executive Officer
(Principal Executive Officer) 	 	

 	/s/ KIRKLAND B. ANDREWS  	 	
 	Kirkland B. Andrews 	 	
 	Chief Financial Officer
(Principal Financial Officer) 	 	

 	/s/ DAVID CALLEN	 	
 	David Callen	 	
Date: November 4, 2016	Chief Accounting Officer
(Principal Accounting Officer) 	 	

113

EXHIBIT 31.1
CERTIFICATION
I, Mauricio Gutierrez, certify that:
 	 	
1.	I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;	
 	 	
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 	 	
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and	
 	 	
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):	
 	 	
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and	
 	 	
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.	

 	 	
/s/ MAURICIO GUTIERREZ	 	
Mauricio Gutierrez
Chief Executive Officer
(Principal Executive Officer)	 	
Date: November 4, 2016 

EXHIBIT 31.2
CERTIFICATION
I, Kirkland B. Andrews, certify that:
 	 	
1.	I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;	
 	 	
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 	 	
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and	
 	 	
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):	
 	 	
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and	
 	 	
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.	

 	 	
/s/ KIRKLAND B. ANDREWS	 	
Kirkland B. Andrews
Chief Financial Officer
(Principal Financial Officer)	 	
Date: November 4, 2016 

EXHIBIT 31.3
CERTIFICATION
I, David Callen, certify that:
 	 	
1.	I have reviewed this quarterly report on Form 10-Q of NRG Energy, Inc.;	
 	 	
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 	 	
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 	 	
4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 	 	
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 	 	
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 	 	
(c)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 	 	
(d)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and	
 	 	
5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):	
 	 	
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and	
 	 	
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.	

 	 	
/s/ DAVID CALLEN	 	
David Callen
Chief Accounting Officer
(Principal Accounting Officer)	 	
Date: November 4, 2016 

EXHIBIT 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of NRG Energy, Inc. on Form 10-Q for the quarter ended September 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-Q”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:
 	 	
(1)	The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 	 	
(2)	
The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of the dates and for the periods expressed in the Form 10-Q.	

Date: November 4, 2016 

 	 	 	 	 	
 	/s/ MAURICIO GUTIERREZ 	 	
 	Mauricio Gutierrez	 	
 	Chief Executive Officer
(Principal Executive Officer) 	 	

 	/s/ KIRKLAND B. ANDREWS	 	
 	Kirkland B. Andrews	 	
 	Chief Financial Officer
(Principal Financial Officer) 	 	

 	/s/ DAVID CALLEN	 	
 	David Callen	 	
 	Chief Accounting Officer
(Principal Accounting Officer) 	 	
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this Form 10-Q or as a separate disclosure document.
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NRG Energy, Inc. and will be retained by NRG Energy, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.