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: ~~March 31,~~September 30, 2017

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.

Yes x No o

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

Yes x No o

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



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o
		(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

As of ~~April 30,~~October 31, 2017, there were ~~316,082,221~~316,641,799 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index

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, 2016, and the following:

~~GenOn's and certain~~NRG's ability to achieve the expected benefits of its ~~subsidiaries'~~Transformation Plan;

The potential adverse effects of the GenOn Entities' filings under Chapter 11 of the Bankruptcy Code and restructuring transactions on NRG's operations, management and employees and the risks associated with operating NRG's business during the restructuring process;

Risks and uncertainties associated with the GenOn Entities' Chapter 11 Cases including the ability to ~~continue as a going concern;~~achieve anticipated benefits therefrom;

NRG's ability to engage in successful mergers and acquisitions activity;

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 (including wind and solar 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 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;

Changes in law, including judicial decisions;

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 Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;

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 coverage;

NRG's ability to develop and build new power generation ~~facilities, including new renewable projects;~~facilities;

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 increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;

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.

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.

GLOSSARY OF TERMS

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



2016 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2016
~~Revolving Credit Facility~~		The Company’s $2.5 billion revolving credit facility, a component of the 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.
2023 Term Loan Facility		The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit ~~Facility.~~Facility
~~ARO~~Adjusted EBITDA		~~Asset Retirement Obligation~~Adjusted earnings before interest, taxes, depreciation and amortization
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
Bankruptcy Code		Chapter 11 of Title 11 of the U.S. Bankruptcy Code
Bankruptcy Court		United States Bankruptcy Court for the Southern District of Texas, Houston Division
BETM		Boston Energy Trading and Marketing LLC
~~BRA~~		~~Base Residual Auction~~
BTU		British Thermal Unit
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CDD		Cooling Degree Day
CDWR		California Department of Water Resources
CEC		California Energy Commission
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
CFTC		U.S. Commodity Futures Trading Commission
Chapter 11 Cases		Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court
COD		Commercial Operation Date
ComEd		Commonwealth Edison
Company		NRG Energy, Inc.
CPP		Clean Power Plan
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CVSR		California Valley Solar Ranch
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
Distributed Solar		Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid
DSI		Dry Sorbent Injection
Economic gross margin		Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
ELG		Effluent Limitations Guidelines
El Segundo Energy Center		NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
EME		Edison Mission Energy
Energy Plus Holdings		Energy Plus Holdings 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
FGD		Flue gas desulfurization
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~~Entities		GenOn ~~Mid-Atlantic, LLC~~ and ~~except where~~certain of its wholly owned subsidiaries, including GenOn Americas Generation. that filed voluntary petitions for relief under Chapter 11 of the ~~context indicates otherwise, its subsidiaries, which include~~Bankruptcy Code in the ~~coal generation units at two generating facilities under operating leases~~Bankruptcy Court on June 14, 2017
GenOn Senior Notes		GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and ~~$490~~$489 million of 9.875% senior notes due 2020
GHG		Greenhouse Gas
GW		Gigawatt
GWh		Gigawatt Hour
HAP		Hazardous Air Pollutant
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
IASB		Independent Accounting Standards Board
IFRS		International Financial Reporting Standards
ILU		Illinois Union Insurance Company
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
ITC		Investment Tax Credit
LaGen		Louisiana Generating, L.L.C.
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG Long-Term Incentive Plan, as amended, and the NRG GenOn Long-Term Incentive Plan
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
MDth		Thousand Dekatherms
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.



MMBtu		Million British Thermal Units
MW		Megawatts
MWh		Saleable megawatt hour net of internal/parasitic load megawatt-hour



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
NO_x		Nitrogen Oxides
NPDES		National Pollutant Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG		NRG Energy, Inc.
NRG Yield		Reporting segment including the projects owned 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 ~~53.4%~~53.7% 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
NSR		New Source Review
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
NYAG		State of New York Office of Attorney General
NYISO		New York Independent System Operator
NYSPSC		New York State Public Service Commission
OCI/OCL		Other Comprehensive Income/(Loss)
Peaking		Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
PER		Peak Energy Rent
Petition Date		June 14, 2017
PG&E		Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
PM		Particulate Matter
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PTC		Production Tax Credit
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
Repowering		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency
Restructuring Support Agreement		Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto



Retail		Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
Revolving Credit Facility		The Company’s $2.5 billion revolving credit facility, a component of the 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 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.~~Facility
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must-Run


ROFO Agreement		Second Amended and Restated Right of First Offer Agreement between the Company and NRG Yield, Inc.
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		NRG's senior secured credit facility, compromised of the Revolving Credit Facility and the 2023 Term Loan 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.~~Facility
Senior Notes		As of ~~March 31,~~September 30, 2017, the Company’s $5.4 billion outstanding unsecured senior notes, consisting of $398 million of 7.625% senior notes due 2018, $207 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, $733 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.~~2027
Services Agreement		NRG provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn
Settlement Agreement		A settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries
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
SO₂		Sulfur Dioxide
SPP		Solar Power Partners
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
S&P		Standard & Poor's
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.
TSA		Transportation Services Agreement
TWCC		Texas Westmoreland Coal Co.
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
WST		Washington-St. Tammany Electric Cooperative, Inc.

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 March 31,						Three months ended September 30,						Nine months ended September 30,
(In millions, except for per share amounts)	2017			2016			2017			2016			2017			2016
Operating Revenues
Total operating revenues	$	2,759		$	3,229		$	3,049		$	3,421		$	8,132		$	8,328
Operating Costs and Expenses
Cost of operations	2,125			2,194			2,156			2,440			5,852			5,711
Depreciation and amortization	300			313			272			298			789			826
Impairment losses							14			9			77			65
Selling, general and administrative	272			252			213			277			697			801
Reorganization							18			—			18			—
Development activity expenses	17			26			14			21			49			65
Total operating costs and expenses	2,714			2,785			2,687			3,045			7,482			7,468
Gain on sale of assets	2			32
Other income - affiliate							14			48			104			144
Gain/(loss) on sale of assets							—			4			4			(79		)
Operating Income	47			476			376			428			758			925
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	5			(7		)
Equity in earnings of unconsolidated affiliates							27			16			29			13
Impairment loss on investment	—			(146		)	—			(8		)	—			(147		)
Other income, net	12			18			15			7			33			29
(Loss)/gain on debt extinguishment, net	(2		)	11
Loss on debt extinguishment, net							(1		)	(50		)	(3		)	(119		)
Interest expense	(269		)	(284		)	(221		)	(237		)	(692		)	(718		)
Total other expense	(254		)	(408		)	(180		)	(272		)	(633		)	(942		)
(Loss)/Income Before Income Taxes	(207		)	68
Income tax (benefit)/expense	(4		)	21
Net (Loss)/Income	(203		)	47
Income/(Loss) from Continuing Operations Before Income Taxes							196			156			125			(17		)
Income tax expense							6			28			5			75
Income/(Loss) from Continuing Operations							190			128			120			(92		)
(Loss)/Income from discontinued operations, net of income tax							(27		)	265			(802		)	256
Net Income/(Loss)							163			393			(682		)	164
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	(40		)	(35		)	(8		)	(9		)	(63		)	(49		)
Net (Loss)/Income Attributable to NRG Energy, Inc.	(163		)	82
Net Income/(Loss) Attributable to NRG Energy, Inc.							171			402			(619		)	213
Dividends for preferred shares	—			5			—			—			—			5
(Loss)/Income Available for Common Stockholders	$	(163	)	$	77
(Loss)/Earnings per Share Attributable to NRG Energy, Inc. Common Stockholders
Gain on redemption of preferred shares							—			—			—			(78		)
Net Income/(Loss) Available for Common Stockholders							$	171		$	402		$	(619	)	$	286
Income/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	316			315			317			316			317			315
(Loss)/Earnings per Weighted Average Common Share — Basic	$	(0.52	)	$	0.24
Income from continuing operations per weighted average common share — basic							$	0.63		$	0.43		$	0.58		$	0.10
(Loss)/Income from discontinued operations per weighted average common share — basic							$	(0.09	)	$	0.84		$	(2.53	)	$	0.81
Income/(Loss) per Weighted Average Common Share — Basic							$	0.54		$	1.27		$	(1.95	)	$	0.91
Weighted average number of common shares outstanding — diluted	316			315			322			317			317			316
(Loss)/Earnings per Weighted Average Common Share — Diluted	$	(0.52	)	$	0.24
Income from continuing operations per weighted average common share — diluted							$	0.61		$	0.43		$	0.58		$	0.10
(Loss)/Income from discontinued operations per weighted average common share — diluted							$	(0.08	)	$	0.84		$	(2.53	)	$	0.81
Income/(Loss) per Weighted Average Common Share — Diluted							$	0.53		$	1.27		$	(1.95	)	$	0.91
Dividends Per Common Share	$	0.03		$	0.15		$	0.03		$	0.03		$	0.09		$	0.21

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)

Three months ended March 31,
2017 2016
(In millions)
Net (loss)/income $ (203 )
$ 47
Other comprehensive income/(loss), net of tax

Unrealized income/(loss) on derivatives, net of income tax expense of $1, and $1 4

(32 )
Foreign currency translation adjustments, net of income tax expense of $0, and $0 7

6
Available-for-sale securities, net of income tax expense of $0, and $0 —

3
Defined benefit plans, net of income tax expense of $0, and $0 —

1
Other comprehensive income/(loss) 11
(22 )
Comprehensive (loss)/income (192 ) 25
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests (39 )
(52 )
Comprehensive (loss)/income attributable to NRG Energy, Inc. (153 ) 77
Dividends for preferred shares —

5
Comprehensive (loss)/income available for common stockholders $ (153 ) $ 72



	Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016
	(In millions)
Net income/(loss)	$	163		$	393		$	(682	)	$	164
Other comprehensive income/(loss), net of tax
Unrealized gain/(loss) on derivatives, net of income tax (benefit)/expense of $0, $(1), $1, and $1	7			27			6			(8		)
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0	2			3			10			6
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0	1			—			2			1
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0	(1		)	31			26			32
Other comprehensive income	9			61			44			31
Comprehensive income/(loss)	172			454			(638		)	195
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests	(5		)	(2		)	(61		)	(70		)
Comprehensive income/(loss) attributable to NRG Energy, Inc.	177			456			(577		)	265
Dividends for preferred shares	—			—			—			5
Gain on redemption of preferred shares	—			—			—			(78		)
Comprehensive income/(loss) available for common stockholders	$	177		$	456		$	(577	)	$	338

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2017			December 31, 2016			September 30, 2017			December 31, 2016
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,513		$	1,973		$	1,223		$	938
Funds deposited by counterparties	3			2			31			2
Restricted cash	397			446			537			446
Accounts receivable, net	974			1,166			1,274			1,058
Inventory	1,140			1,111			630			721
Derivative instruments	682			1,062			475			1,067
Cash collateral paid in support of energy risk management activities	277			203
Current assets held-for-sale	—			9
Cash collateral posted in support of energy risk management activities							203			150
Current assets - held for sale							33			9
Prepayments and other current assets	454			423			354			404
Current assets - discontinued operations							—			1,919
Total current assets	5,440			6,395			4,760			6,714
Property, plant and equipment, net	17,942			17,912			15,332			15,369
Other Assets
Equity investments in affiliates	1,148			1,120			1,138			1,120
Notes receivable, less current portion	13			17			5			16
Goodwill	662			662			662			662
Intangible assets, net	1,957			2,036			1,838			1,973
Nuclear decommissioning trust fund	627			610			670			610
Derivative instruments	226			189			206			181
Deferred income taxes	223			225			205			225
Non-current assets held-for-sale	10			10			10			10
Other non-current assets	1,172			1,179			644			841
Non-current assets - discontinued operations							—			2,961
Total other assets	6,038			6,048			5,378			8,599
Total Assets	$	29,420		$	30,355		$	25,470		$	30,682
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,688		$	1,220		$	1,247		$	516
Accounts payable	872			895			911			813
Derivative instruments	747			1,084			522			1,092
Cash collateral received in support of energy risk management activities	3			2			31			81
Accrued expenses and other current liabilities	887			1,181			830			990
Accrued expenses and other current liabilities - affiliate							164			—
Current liabilities - discontinued operations							—			1,210
Total current liabilities	4,197			4,382			3,705			4,702
Other Liabilities
Long-term debt and capital leases	17,672			18,006			15,658			15,957
Nuclear decommissioning reserve	291			287			265			287
Nuclear decommissioning trust liability	352			339			397			339
Deferred income taxes	20			20			21			20
Derivative instruments	315			294			307			284
Out-of-market contracts, net	1,017			1,040			213			230
Non-current liabilities held-for-sale	12			12			13			11
Other non-current liabilities	1,487			1,483			1,116			1,176
Non-current liabilities - discontinued operations							—			3,184
Total non-current liabilities	21,166			21,481			17,990			21,488
Total Liabilities	25,363			25,863			21,695			26,190
Redeemable noncontrolling interest in subsidiaries	44			46			85			46
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4			4			4
Additional paid-in capital	8,375			8,358			8,369			8,358
Retained deficit	(4,238		)	(3,787		)	(4,713		)	(3,787		)
Less treasury stock, at cost — 101,858,284 and 102,140,814 shares, respectively	(2,392		)	(2,399		)
Less treasury stock, at cost — 101,580,045 and 102,140,814 shares, respectively							(2,386		)	(2,399		)
Accumulated other comprehensive loss	(124		)	(135		)	(91		)	(135		)
Noncontrolling interest	2,388			2,405			2,507			2,405
Total Stockholders’ Equity	4,013			4,446			3,690			4,446
Total Liabilities and Stockholders’ Equity	$	29,420		$	30,355		$	25,470		$	30,682

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three months ended March 31,						Nine months ended September 30,
	2017			2016
	(In millions)
(In millions)							2017			2016
Cash Flows from Operating Activities
Net (loss)/income	$	(203	)	$	47		$	(682	)	$	164
(Loss)/Income from discontinued operations, net of income tax							(802		)	256
Income/(loss) from continuing operations							120			(92		)
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	8			17			24			44
Depreciation and amortization	300			313			789			826
Provision for bad debts	9			10			57			36
Amortization of nuclear fuel	12			13			37			39
Amortization of financing costs and debt discount/premiums	1			1			44			42
Adjustment for debt extinguishment	—			(11		)	3			119
Amortization of intangibles and out-of-market contracts	10			26			79			131
Amortization of unearned equity compensation	8			8			27			23
Impairment losses	—			146			77			211
Changes in deferred income taxes and liability for uncertain tax benefits	1			(25		)	26			29
Changes in nuclear decommissioning trust liability	36			9			20			24
Changes in derivative instruments	25			(50		)	25			30
Changes in collateral posted in support of risk management activities	(74		)	156			(103		)	261
Proceeds from sale of emission allowances	—			47			21			11
Gain on sale of assets	(2		)	(32		)
Cash used by changes in other working capital	(199		)	(121		)
Net Cash (Used)/Provided by Operating Activities	(68		)	554
(Gain)/loss on sale of assets							(22		)	70
Changes in other working capital							(380		)	(130		)
Cash provided by continuing operations							844			1,674
Cash (used)/provided by discontinued operations							(38		)	67
Net Cash Provided by Operating Activities							806			1,741
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(3		)	(6		)	(36		)	(18		)
Capital expenditures	(268		)	(279		)	(760		)	(659		)
Decrease/(increase)in restricted cash, net	13			(12		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	36			39
Decrease in notes receivable	4			1			11			2
Purchases of emission allowances	(9		)	(12		)	(47		)	(32		)
Proceeds from sale of emission allowances	11			7			105			47
Investments in nuclear decommissioning trust fund securities	(153		)	(200		)	(402		)	(378		)
Proceeds from the sale of nuclear decommissioning trust fund securities	117			191			382			354
Proceeds from renewable energy grants and state rebates	—			8			8			11
Proceeds from sale of assets, net of cash disposed of	14			120			36			84
Investments in unconsolidated affiliates	(12		)	(4		)	(31		)	(23		)
Other	18			4			22			31
Cash used by continuing operations							(712		)	(581		)
Cash (used)/provided by discontinued operations							(53		)	326
Net Cash Used by Investing Activities	(232		)	(143		)	(765		)	(255		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(9		)	(48		)	(28		)	(66		)
Payment for preferred shares							—			(226		)
Net receipts from settlement of acquired derivatives that include financing elements	1			39			2			6
Proceeds from issuance of long-term debt	192			61			1,134			5,237
Payments for short and long-term debt	(177		)	(316		)	(712		)	(5,353		)
Payment for credit support in long-term deposits	(130		)	—
Proceeds from draw on revolving credit facility for long-term deposits	125			—
Increase in long-term deposits	(125		)	—
Contributions to, net of distributions from, noncontrolling interest in subsidiaries	(5		)	10
Receivable from affiliate							(125		)	—
Payments for debt extinguishment costs							—			(98		)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries							65			(127		)
Proceeds from issuance of stock							—			1
Payment of debt issuance costs	(15		)	—			(43		)	(70		)
Other - contingent consideration	(10		)	(10		)	(10		)	(10		)
Net Cash Used by Financing Activities	(153		)	(264		)
Cash provided/(used) by continuing operations							283			(706		)
Cash (used)/provided by discontinued operations							(224		)	119
Net Cash provided/(used) by Financing Activities							59			(587		)
Effect of exchange rate changes on cash and cash equivalents	(7		)	(6		)	(10		)	(6		)
Net (Decrease)/ Increase in Cash and Cash Equivalents	(460		)	141
Cash and Cash Equivalents at Beginning of Period	1,973			1,518
Cash and Cash Equivalents at End of Period	$	1,513		$	1,659
Change in Cash from discontinued operations							(315		)	512
Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash							405			381
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period							1,386			1,322
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period							$	1,791		$	1,703

See accompanying notes to condensed consolidated financial statements.

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 a leading integrated power company built on the strength of ~~the nation's largest and most~~a diverse competitive electric generation portfolio and leading retail electricity platform. NRG ~~aims to create a sustainable~~is continuously focused on excellence in operating performance of its existing assets and optimal hedging of generation assets and retail load operations, as well as serving the energy ~~future by producing, selling~~needs of end-use residential, commercial and ~~delivering electricity~~industrial customers in competitive markets through multiple brands and ~~related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders.~~channels. The Company owns and operates approximately ~~46,000~~30,000 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 2016 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 ~~March 31,~~September 30, 2017, and the results of operations, comprehensive income/(loss) and cash flows for the three and nine months ended ~~March 31,~~September 30, 2017 and 2016.

GenOn ~~Liquidity and Ability to Continue as a Going Concern~~Chapter 11 Cases

~~As of March 31,~~On June 14, 2017, or the Petition Date, GenOn, ~~had cash and cash equivalents of $885 million, of which $305 million and $82 million were held by~~along with 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, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective leases. As a result, GenOn Mid-Atlantic has not been able to make distributions of cashAmericas Generation 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~~their directly and ~~certain other restricted payments since 2009.~~

~~As disclosed in Note 8,~~ ~~Debt and Capital Leases, $691 million of GenOn's Senior Notes, excluding $4 million of associated premiums, are current within~~indirectly-owned subsidiaries, or collectively the GenOn consolidated balance sheet as of March 31, 2017 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. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibilityEntities, filed voluntary petitions for ~~a need to file for protection~~relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy ~~Code. If~~Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn ~~is unable to enter into a settlement with~~Mid-Atlantic, as well as its ~~creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is~~consolidated subsidiaries, REMA and certain other subsidiaries, did not ~~expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern.~~ file for relief under Chapter 11.

As a result of the ~~substantial doubt about GenOn’s ability~~bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated fair value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation; and, accordingly, the financial information for all historical periods have been recast to ~~continue~~reflect GenOn as a ~~going concern, along~~discontinued operation. In connection with ~~additional factors, there~~the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for more information.

Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. The RSA was amended on October 2, 2017 to remove the requirement to conduct a rights offering in connection with the exit financing. There is ~~substantial doubt about~~no assurance that the GenOn Entities' plan will be approved by the requisite stakeholders, confirmed by the Bankruptcy Court, or successfully implemented thereafter. The principal terms of the Restructuring Support Agreement are described further in Note 3, Discontinued Operations, Dispositions and Acquisitions.

As announced on October 31, 2017, NRG and GenOn engaged in arms-length discussions to settle certain ofitems related to the pre-petition Restructuring Support Agreement, including key topics such as: (i) timeline and transition; (ii) cooperation and co-development matters; (iii) post-employment and retiree health and welfare benefits and pension benefits; (iv) tax matters; and (v) intercompany balances. The agreements reached on these topics are expected to be incorporated into definitive documents for GenOn’s ~~subsidiaries’ ability to continue as a going concern.~~

During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the NRG's statement of operations, cash flows and financial position.emergence from Chapter 11.

Forms of definitive documents were filed with the Bankruptcy Court by the GenOn Entities; however, such definitive documents are subject to ongoing review, revision, and further negotiation by the parties to the Restructuring Support Agreement, including NRG, ~~GenOn's parent company, has no obligation~~who have various consent rights over the final form of the plan supplement documents, and may be amended, modified, supplemented, and revised in accordance with those ongoing negotiations.

Transformation Plan

On July 12, 2017, NRG announced its Transformation Plan designed to ~~provide any financial support~~significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following targets:

Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.

Portfolio optimization — Targeting up to ~~GenOn other than under~~$4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the ~~secured intercompany revolving credit agreement between~~expected monetization of 100% of its interest in NRG Yield, Inc. and ~~GenOn~~its renewables platform.

Capital structure and ~~NRG Americas. As~~allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of ~~March 31, 2017, $214 million was available~~the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be ~~used~~available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.

The Company expects to fully implement the Transformation Plan by ~~GenOn under~~ the ~~$500~~end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million ~~revolving credit agreement. As controlled group members, ERISA requires that NRG~~of non-recurring working capital improvements through 2020 and ~~GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.~~(ii) approximately $290 million, one-time costs to achieve.

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.

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:


	March 31, 2017		December 31, 2016		September 30, 2017		December 31, 2016
	(In millions)				(In millions)
Accounts receivable allowance for doubtful accounts	$	33	$	30	$	61	$	29
Property, plant and equipment accumulated depreciation	6,602		6,314		6,437		5,711
Intangible assets accumulated amortization	1,724		1,775		1,750		1,687
Out-of-market contracts accumulated amortization	666		765		352		457

Restricted Cash

The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by counterparties reported within the consolidated balance sheet that sum to the total of the same such amounts shown in the statement of cash flows.



	September 30, 2017		December 31, 2016		September 30, 2016		December 31, 2015
	(In millions)
Cash and cash equivalents	$	1,223	$	938	$	1,217	$	853
Funds deposited by counterparties	31		2		6		55
Restricted cash	537		446		480		414
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,791	$	1,386	$	1,703	$	1,322

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. As of December 31, 2016, $79 million of the cash collateral received was from GenOn, previously a consolidated subsidiary, and is included in cash collateral received in current liabilities as a result of deconsolidating GenOn, with the offset included in cash and cash equivalents.

Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use.

Noncontrolling Interest

The following table reflects the changes in NRG's noncontrolling interest balance:


	(In millions)			(In millions)
Balance as of December 31, 2016	$	2,405		$	2,405
Contributions from noncontrolling interest				116
Non-cash adjustments to noncontrolling interest				98
Sale of assets to NRG Yield, Inc.				24
Comprehensive loss attributable to noncontrolling interest				(8		)
Dividends paid to NRG Yield, Inc. public shareholders	(25		)	(80		)
Comprehensive loss attributable to noncontrolling interest	(22		)
Distributions to noncontrolling interest	(21		)	(48		)
Contributions from noncontrolling interest	48
Sale of assets to NRG Yield, Inc.	3
Balance as of March 31, 2017	$	2,388
Balance as of September 30, 2017				$	2,507

Redeemable Noncontrolling Interest

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


	(In millions)			(In millions)
Balance as of December 31, 2016	$	46		$	46
Contributions from redeemable noncontrolling interest	15			73
Non-cash adjustments to noncontrolling interest				21
Comprehensive loss attributable to redeemable noncontrolling interest	(17		)	(53		)
Balance as of March 31, 2017	$	44
Distributions to redeemable noncontrolling interest				(2		)
Balance as of September 30, 2017				$	85

Recent Accounting Developments - Guidance Adopted in 2017

ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 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. 2016-18 will be applied retrospectively. The Company adopted the guidance in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in a decrease in cash flows from operations of $49 million and an increase in cash flows from investing of $66 million on the statement of cash flows for the nine months ended September 30, 2016.

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. 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. The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit.

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 Company adopted the guidance in ASU No. 2016-15 effective January 1, 2017. ~~While the Company has applied this guidance retrospectively,~~In connection with the adoption of the standard, ~~did not have~~the Company has applied the guidance retrospectively which resulted in an ~~impact~~increase in cash flows from operations of $98 million and a decrease in cash flows from financing of $98 million on the statement of cash ~~flow~~flows for the ~~three~~nine months ended ~~March 31,~~September 30, 2016.

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 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 Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017 with no material adjustments recorded to the consolidated balance sheet.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. The amendments of ASU No. 2017-12 were issued to simplify the application of hedge accounting guidance and more closely align financial reporting for hedging relationships with economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The amendments of ASU No. 2017-12 are effective for fiscal years beginning after December 15, 2018, and interim periods therein. Early adoption is permitted in any interim period and the effect of the adoption should be reflected as of the beginning of the fiscal year of adoption. The Company does not expect the adoption of ASU No. 2017-12 will have a material impact on its consolidated results of operations, cash flows, and statement of financial position.

ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07. Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The amendments of ASU No. 2017-07 are effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and must be applied on a retrospective basis, except for the amendments regarding the capitalization of the service cost component, which must be applied prospectively. The Company is currently assessing the impact that the adoption of ASU No. 2017-07 will have on its results of operations, cash flows, and statement of financial position.

ASU ~~2016-18~~ ~~— In November 2016, the FASB issued ASU No. 2016-18,~~ ~~Statement of Cash Flows (Topic 230)~~, Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 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. 2016-18 will be applied retrospectively. The Company calculated the impact of ASU No. 2016-18 on the statement of cash flows to be a decrease of cash flows used by operating activities of $1 million and an increase of cash flows used by investing activities of $49 million for the three months ended March 31, 2017, and a decrease of cash flows provided by operating activities of $5 million and a decrease of cash flows used by investing activities of $27 million for the three months ended March 31, 2016.

~~ASU~~ 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, 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 by expanding the related disclosures. The guidance in Topic 842 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, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. AsWhile this review is still in process, ~~it is currently not practicable to quantify~~NRG believes the adoption of Topic 842 will have a material impact ~~of adopting the ASU at this time.~~on its financial statements.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of Topic 606 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. 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 five step model to be applied by an entity in evaluating its contracts with customers. The Company expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that

corresponds directly with the value to the customer for performance completed to date by the entity. The Company continues to assess the new standard with a focus on identifying the performance obligations included within its revenue arrangements with customers and evaluating the Company’s methods of estimating the amount and timing of variable consideration. ~~Based on~~While the ~~assessment~~impact remains subject to ~~date,~~continued review, the Company ~~is currently evaluating~~does not believe the adoption of Topic 606 will have a material impact ~~of the new standard~~ on ~~the Company’s results of operations,~~its financial ~~position or cash flows.~~statements.

Note 3 — Discontinued Operations, Dispositions and Acquisitions

Discontinued Operations

As described in Note 1, Basis of Presentation, on the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controls GenOn as it is subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidates GenOn for financial reporting purposes.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn meets the criteria for discontinued operations, as this represents a strategic shift in the markets in which NRG operates. As such, all prior period results for GenOn have been reclassified as discontinued operations while NRG will record all ongoing results of GenOn as a cost method investment, which was valued at zero at the date of deconsolidation.

Summarized results of discontinued operations were as follows:



	Three months ended September 30, 2017 ^(a)			Three months ended September 30, 2016			Nine months ended September 30, 2017 ^(a)			Nine months ended September 30, 2016
(In millions)	Three months ended September 30, 2017 ^(a)			Three months ended September 30, 2016			Nine months ended September 30, 2017 ^(a)			Nine months ended September 30, 2016
Operating revenues	$	—		$	532		$	646		$	1,509
Operating costs and expenses	—			(468		)	(700		)	(1,409		)
Gain on sale of assets	—			262			—			294
Other expenses	—			(43		)	(98		)	(127		)
(Loss)/Income from operations of discontinued components, before tax	—			283			(152		)	267
Income tax expense	—			21			9			20
(Loss)/Incomes from operations of discontinued components	—			262			(161		)	247
Interest income - affiliate	—			3			6			9
(Loss)/Income from operations of discontinued components, net of tax	—			265			(155		)	256
Pre-tax loss on deconsolidation	—			—			(208		)	—
Settlement consideration and services credit	—			—			(289		)	—
Pension and post-retirement liability assumption^(b)	(25		)	—			(144		)	—
Other	(2		)	—			(6		)	—
Loss on disposal of discontinued components, net of tax	(27		)	—			(647		)	—
(Loss)/Income from discontinued operations, net of tax	$	(27	)	$	265		$	(802	)	$	256

(a) As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.

(b) See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement. As part of this, NRG recorded the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million with a corresponding loss on discontinued operations during the third quarter of 2017.

The ~~Company~~following table summarizes the major classes of assets and liabilities classified as discontinued operations as of December 31, 2016. As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.



(In millions)	December 31, 2016
Cash and cash equivalents	$	1,034
Other current assets	885
Current assets - discontinued operations	1,919
Property, plant and equipment, net	2,543
Other non-current assets	418
Non-current assets - discontinued operations	2,961
Current portion of long term debt and capital leases	704
Other current liabilities	506
Current liabilities - discontinued operations	1,210
Long-term debt and capital leases	2,050
Out-of-market contracts	811
Other non-current liabilities	323
Non-current liabilities - discontinued operations	$	3,184

Restructuring Support Agreement

As described in Note 1, Basis of Presentation, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring Support Agreement. Certain principal terms of the Restructuring Support Agreement are detailed below:


1)	Full releases from GenOn and GenOn Americas Generation in favor of NRG, including either a full release or indemnification in favor of NRG for any claims relating to GenOn Mid-Atlantic or REMA and the dismissal of all litigation against NRG.

NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of September 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility.


3)	NRG will consent to the cancellation of its interests in the equity of GenOn. The equity interests in the reorganized GenOn will be issued to the holders of the GenOn Senior Notes.


4)	NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million.

The shared services agreement between NRG and GenOn will be amended such that (i) NRG will provide shared services to GenOn at an annualized rate of $84 million during the pendency of the Chapter 11 Cases, (ii) if the settlement is approved by the bankruptcy court, NRG will provide shared services to GenOn at no charge for two months, and (iii) NRG will then provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. See Note 14, Related Party Transactions, for further discussion of the shared services agreement.


6)	NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the shared services agreement upon emergence from bankruptcy. Any unused amount can be paid in cash at GenOn’s request. The credit was intended to reimburse GenOn for its payment of financing costs.

NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn had obtained a separate letter of credit facility with a third party financial institution. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolver credit facility and the letter of credit facility obtained in July 2017.


8)	NRG and GenOn have agreed to cooperate in good faith to maximize the value of certain development projects.

In addition to the Restructuring Support Agreement, additional support and other agreements are being negotiated, including a transition services agreement. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement.

Settlement Consideration

NRG has determined that the payment of the settlement consideration is probable and has recorded a liability for the amount due of $261.3 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. NRG expects to pay this amount net of amounts due from GenOn under the intercompany secured revolving credit facility, which is further described in Note 14, Related Party Transactions.

Pension Liability

NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, which was paid in September 2017, for the GenOn employees for service provided prior to emergence from bankruptcy. NRG determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of September 30, 2017 of $106 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation for this liability will be revalued through and at GenOn's emergence from bankruptcy.

Services Agreement

NRG will continue to provide shared services to GenOn under the Services Agreement at an annualized rate of $84 million during the pendency of the Chapter 11 Cases as well as for two months post-emergence at no charge. NRG then will provide an option for up to two, one-month extensions for shared services at an annualized rate of $84 million. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. NRG has also agreed to provide GenOn with a credit of $28 million against amounts owed under the Services Agreement. Any unused amount can be paid in cash at GenOn’s request. As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement.

Commercial Operations

For pre-disposal periods, NRG provided GenOn with services as described in Note 14, Related Party Transactions. Under intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. For current and pre-disposal periods, revenue and expense associated with these transactions is recorded in continuing operations.

GenOn Debt

As of June 14, 2017, the GenOn Senior Notes and GenOn Americas Generation Senior Notes, which totaled approximately $2.5 billion, were deconsolidated from NRG's consolidated financial statements. The filing of the Chapter 11 Cases constitutes an event of default under the following debt instruments of GenOn:


1)	The intercompany secured revolving credit facility with NRG;


2)	The indenture governing the GenOn 7.875% Senior Notes due 2017 (as amended or supplemented from time to time);


3)	The indenture governing the GenOn 9.500% Notes due 2018 (as amended or supplemented from time to time);


4)	The indenture governing the GenOn 9.875% Notes due 2020 (as amended or supplemented from time to time);


5)	The indenture governing the GenOn Americas Generation 8.50% Senior Notes due 2021 (as amended or supplemented from time to time); and


6)	The indenture governing the GenOn Americas Generation 9.125% Senior Notes due 2031 (as amended or supplemented from time to time).

Transfer of Assets Under Common Control

On November 1, 2017, NRG completed the ~~following transfer~~sale of a 38 MW solar portfolio primarily comprised of assets ~~under common control.~~from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.

On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustment of $3 million. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.

On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity, which have reached commercial operations. NRG Yield, Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.

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.

Acquisitions

SunEdison Utility-Scale Solar and Wind Acquisition

On November 2, 2016, the Company acquired equity interests in a tax equity portfolio from SunEdison, located in Utah, comprised of 530 MW of mechanically-complete solar assets, of which NRG’s net interest based on cash to be distributed is 265 MW, for upfront cash consideration of $111 million. In connection with the acquisition, the Company assumed non-recourse debt of $222 million. The Company also borrowed additional amounts of $65 million during the fourth quarter of 2016, which effectively reduced the Company's use of liquidity related to the acquisition. The Company does not have a controlling interest in the tax equity portfolio and, accordingly, its interest is recorded as an equity method investment. The purchase price was preliminarily allocated to the equity method investment balance of approximately $328 million, current assets of $5 million and the assumed non-recourse debt of $222 million. The assets reached commercial operations during the fourth quarter of 2016 and have 20-year PPAs with PacificCorp.

The Company acquired a 110 MW portfolio of construction-ready and 71 MW of development solar assets in Hawaii from SunEdison for upfront cash consideration of $2 million on October 3, 2016 and a 154 MW construction-ready solar project in Texas for upfront cash consideration of $11 million on November 9, 2016.

In addition to the total $124 million in upfront cash consideration paid for the above acquisitions, the Company expects to make an estimated $59 million in additional payments contingent upon future development milestones, of which $15 million was paid as of September 30, 2017.

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 $67 million excluding post-closing adjustments which reduced the purchase price by $5 million. Subsequent to the acquisition, the Company sold the majority of these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc., and expects to sell the remaining assets into a similar portfolio in 2017. The purchase price was allocated to $47 million in construction in progress and $15 million in intangible assets.

Dispositions

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 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. As part of the sale, 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 will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $83 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. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended the operating period commitment for the Freedom Stations to December 5, 2020. At September 30, 2017, the Company's remaining 35% interest in EVgo of $2 million was accounted for as an equity-method investment.

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. At June 30, 2016, the Company had $2 million of current assets and $54 million of non-current assets classified as held for sale for Rockford on its balance sheet. 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, to this Form 10-Q.

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 2016 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 March 31, 2017				As of December 31, 2016				As of September 30, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)								(In millions)
Assets:
Notes receivable^(a)	$	30	$	30	$	34	$	34	$	22	$	21	$	34	$	34
Liabilities:
Long-term debt, including current portion^(b)	19,539		18,726		19,406		18,566		17,097		17,423		16,655		16,620

(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 ~~March 31,~~September 30, 2017 and December 31, 2016:

As of March 31, 2017 As of December 31, 2016
Level 2 Level 3 Level 2 Level 3
(In millions)
Long-term debt, including current portion $ 11,190
$ 7,536
$ 11,055
$ 7,511



	As of September 30, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	9,571	$	7,852	$	9,205	$	7,415

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 March 31, 2017								As of September 30, 2017
	Fair Value								Fair Value
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	18	$	18	$	—	$	—	$	19	$	19
Available-for-sale securities	4		—		—		4		5		—		—		5
Other ^(a)	8		—		—		8
Nuclear trust fund investments:
Cash and cash equivalents	16		—		—		16		31		—		—		31
U.S. government and federal agency obligations	55		1		—		56		43		1		—		44
Federal agency mortgage-backed securities	—		67		—		67		—		74		—		74
Commercial mortgage-backed securities	—		17		—		17		—		11		—		11
Corporate debt securities	—		100		—		100		—		108		—		108
Equity securities	309		—		58		367		333		—		65		398
Foreign government fixed income securities	—		4		—		4		—		4		—		4
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1		1		—		—		1
Derivative assets:
Commodity contracts	245		534		79		858		132		409		98		639
Interest rate contracts	—		50		—		50		—		42		—		42
Total assets	$	638	$	773	$	155	$	1,566	$	545	$	649	$	182	$	1,376
Derivative liabilities:
Commodity contracts	307		541		137		985		201		404		146		751
Interest rate contracts	—		77		—		77		—		78		—		78
Total liabilities	$	307	$	618	$	137	$	1,062	$	201	$	482	$	146	$	829

~~(a) Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for certain former employees.~~.


	As of December 31, 2016								As of December 31, 2016
	Fair Value								Fair Value
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	17	$	17	$	—	$	—	$	17	$	17
Available-for-sale securities	10		—		—		10		10		—		—		10
Other ^(a)	10		—		—		10
Nuclear trust fund investments:
Cash and cash equivalents	25		—		—		25		25		—		—		25
U.S. government and federal agency obligations	72		1		—		73		72		1		—		73
Federal agency mortgage-backed securities	—		62		—		62		—		62		—		62
Commercial mortgage-backed securities	—		17		—		17		—		17		—		17
Corporate debt securities	—		84		—		84		—		84		—		84
Equity securities	292		—		54		346		292		—		54		346
Foreign government fixed income securities	—		3		—		3		—		3		—		3
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1		1		—		—		1
Derivative assets:
Commodity contracts	559		551		92		1,202		560		549		90		1,199
Interest rate contracts	—		49		—		49		—		49		—		49
Total assets	$	969	$	767	$	163	$	1,899	$	960	$	765	$	161	$	1,886
Derivative liabilities:
Commodity contracts	494		635		161		1,290		494		636		158		1,288
Interest rate contracts	—		88		—		88		—		88		—		88
Total liabilities	$	494	$	723	$	161	$	1,378	$	494	$	724	$	158	$	1,376

(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 ~~March 31,~~September 30, 2017 and 2016 between Levels 1 and 2. The following tables reconcile, for the three and nine months ended ~~March 31,~~September 30, 2017 and 2016, 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)										Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2017										Three months ended September 30, 2017										Nine months ended September 30, 2017
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	17	$	54	$	(69	)	$	2		$	18	$	61	$	(11	)	$	68		$	17	$	54	$	(68	)	$	3
Total gains — realized/unrealized:
Total gains/(losses) — realized/unrealized:
Included in earnings	1		—		6			7			1		—		(28		)	(27		)	2		—		18			20
Included in nuclear decommissioning obligation	—		4		—			4			—		3		—			3			—		10		—			10
Purchases	—		—		3			3			—		1		(9		)	(8		)	—		1		—			1
Transfers into Level 3 ^(b)	—		—		(8		)	(8		)	—		—		(6		)	(6		)	—		—		(11		)	(11		)
Transfers out of Level 3 ^(b)	—		—		10			10			—		—		6			6			—		—		13			13
Ending balance as of March 31, 2017	$	18	$	58	$	(58	)	$	18
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 March 31, 2017	$	—	$	—	$	(15	)	$	(15	)
Ending balance as of September 30, 2017											$	19	$	65	$	(48	)	$	36		$	19	$	65	$	(48	)	$	36
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, 2017											$	—	$	��	$	(13	)	$	(13	)	$	—	$	—	$	(6	)	$	(6	)


(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.


	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)											Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2016											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			Debt Securities		Trust Fund Investments			Derivatives^(a)			Total
Beginning balance	$	17	$	54		$	(33	)	$	38		$	16	$	51	$	18		$	85		$	17	$	54		$	(22	)	$	49
Total losses — realized/unrealized:
Total (losses)/gains — realized/unrealized:
Included in earnings	—		—			(17		)	(17		)	—		—		(5		)	(5		)	—		—			4			4
Included in OCI												1		—		—			1			—		—			—			—
Included in nuclear decommissioning obligations	—		(2		)	—			(2		)	—		3		—			3			—		(1		)	—			(1		)
Purchases	—		—			5			5			—		—		(25		)	(25		)	—		1			2			3
Transfers into Level 3 ^(b)	—		—			27			27			—		—		(13		)	(13		)	—		—			(6		)	(6		)
Transfers out of Level 3 ^(b)	—		—			1			1			—		—		3			3			—		—			—			—
Ending balance as of March 31, 2016	$	17	$	52		$	(17	)	$	52
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 March 31, 2016	$	—	$	—		$	(24	)	$	(24	)
Ending balance as of September 30, 2016												$	17	$	54	$	(22	)	$	49		$	17	$	54		$	(22	)	$	49
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												$	—	$	—	$	(4	)	$	(4	)	$	—	$	—		$	(11	)	$	(11	)


(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 ~~March 31,~~September 30, 2017, contracts valued with prices provided by models and other valuation techniques make up 9%14% of the total derivative assets and ~~13%~~18% 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.

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of ~~March 31,~~September 30, 2017 and December 31, 2016:


	Significant Unobservable Inputs													Significant Unobservable Inputs
	March 31, 2017													September 30, 2017
	Fair Value						Input/Range							Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)													(In millions)
Power Contracts	$	43	$	97	Discounted Cash Flow	Forward Market Price (per MWh)	$	12		$	88	$	26	$	47	$	101	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	88	$	24
Coal Contracts	—		1		Discounted Cash Flow	Forward Market Price (per ton)	42			48		44
FTRs	36		39		Discounted Cash Flow	Auction Prices (per MWh)	(17		)	19		—		51		45		Discounted Cash Flow	Auction Prices (per MWh)	(31		)	36		—
	$	79	$	137										$	98	$	146


	Significant Unobservable Inputs													Significant Unobservable Inputs
	December 31, 2016													December 31, 2016
	Fair Value						Input/Range							Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)													(In millions)
Power Contracts	$	40	$	107	Discounted Cash Flow	Forward Market Price (per MWh)	$	11		$	104	$	31	$	39	$	108	Discounted Cash Flow	Forward Market Price (per MWh)	$	11		$	104	$	31
Coal Contracts	—		1		Discounted Cash Flow	Forward Market Price (per ton)	42			51		45
FTRs	52		53		Discounted Cash Flow	Auction Prices (per MWh)	(22		)	17		—		51		50		Discounted Cash Flow	Auction Prices (per MWh)	(22		)	17		—
	$	92	$	161										$	90	$	158

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of ~~March 31,~~September 30, 2017 and December 31, 2016:



Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price ~~Power/Coal~~Power	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price ~~Power/Coal~~Power	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 ~~March 31,~~September 30, 2017, the credit reserve resulted in a $2$1 million ~~decrease~~increase in fair value in operating revenue and cost of operations. As of December 31, 2016, the credit reserve resulted in ~~an $11~~a $10 million decrease in fair value in operating revenue 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 2016 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.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2016 Form 10-K. As of ~~March 31,~~September 30, 2017, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $~~191~~134 million with net exposure of ~~$188~~$129 million. NRG held collateral (cash and letters of credit) against those positions of $314 million. Approximately ~~76%~~74% of the Company's exposure before collateral is expected to roll off by the end of 2018. 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) (b)}
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	91	%
Financial institutions	9
Total as of ~~March 31,~~September 30, 2017	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	8779	%
Non-Investment grade/Non-Rated	1321
Total as of ~~March 31,~~September 30, 2017	100	%


(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.


(b)	The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.

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 $7250 million as of ~~March 31,~~September 30, 2017. 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.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of overall market and are excluded from the above exposures.

Exchange Traded Transactions

The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.

Long Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, and wind and solar PPAs. 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 ~~March 31,~~September 30, 2017, aggregate credit risk exposure managed by NRG to these counterparties was approximately ~~$4.4~~$4.3 billion, including ~~$2.9~~$2.8 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 or treatment by regulatory agencies which NRG is unable to predict.

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 ~~March 31,~~September 30, 2017, the Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.

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 2016 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 March 31, 2017							As of December 31, 2016							As of September 30, 2017							As of December 31, 2016
(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)	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	$	16	$	—	$	—	—	$	25	$	—	$	—	—	$	31	$	—	$	—	—	$	25	$	—	$	—	—
U.S. government and federal agency obligations	56		2		—		9	73		1		—		11	44		2		—		10	73		1		—		11
Federal agency mortgage-backed securities	67		1		1		24	62		1		1		25	74		1		1		24	62		1		1		25
Commercial mortgage-backed securities	17		—		1		26	17		—		1		26	11		—		—		23	17		—		1		26
Corporate debt securities	100		1		1		10	84		1		2		11	108		2		1		11	84		1		2		11
Equity securities	367		233		—		—	346		214		—		—	398		260		—		—	346		214		—		—
Foreign government fixed income securities	4		—		—		7	3		—		—		9	4		—		—		9	3		—		—		9
Total	$	627	$	237	$	3		$	610	$	217	$	4		$	670	$	265	$	2		$	610	$	217	$	4

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.


	Three months ended March 31,				Nine months ended September 30,
	2017		2016		2017		2016
	(In millions)				(In millions)
Realized gains	$	2	$	4	$	8	$	7
Realized losses	2		3		6		3
Proceeds from sale of securities	117		191		382		354

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 2016 Form 10-K.

Energy-Related Commodities

As of ~~March 31,~~September 30, 2017, NRG had energy-related derivative instruments extending through 2031. 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 ~~March 31,~~September 30, 2017, 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 ~~2036,~~2041, 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 ~~March 31,~~September 30, 2017 and December 31, 2016. 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							Total Volume
		March 31, 2017			December 31, 2016				September 30, 2017			December 31, 2016
Category	Units	(In millions)						Units	(In millions)
Emissions	Short Ton	(4		)	—			Short Ton	(1		)	—
Coal	Short Ton	32			41			Short Ton	15			35
Natural Gas	MMBtu	162			85			MMBtu	(62		)	(53		)
Oil	Barrel	—			1			Barrel	—			1
Power	MWh	(12		)	(28		)	MWh	19			7
Capacity	MW/Day	(1		)	(1		)	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,369		$	3,429		Dollars	$	3,806		$	3,429
Equity	Shares	1			1			Shares	1			1

The ~~increase~~decrease in the ~~natural gas~~coal position was primarily the result of the settlement of hedge positions, and the increase in the power position was primarily the result of additional ~~generation and~~ retail hedge positions.

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:


	Fair Value								Fair Value
	Derivative Assets				Derivative Liabilities				Derivative Assets				Derivative Liabilities
	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016		September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016
	(In millions)								(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	22	$	28	$	—	$	—	$	8	$	28
Interest rate contracts long-term	12		12		31		41		10		12		15		41
Total derivatives designated as cash flow hedges	12		12		53		69		10		12		23		69
Derivatives not designated as cash flow hedges:
Interest rate contracts current	3		—		8		7		5		—		19		7
Interest rate contracts long-term	35		37		16		12		27		37		36		12
Commodity contracts current	679		1,062		717		1,049		470		1,067		495		1,057
Commodity contracts long-term	179		140		268		241		169		132		256		231
Total derivatives not designated as cash flow hedges	896		1,239		1,009		1,309		671		1,236		806		1,307
Total derivatives	$	908	$	1,251	$	1,062	$	1,378	$	681	$	1,248	$	829	$	1,376

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 Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount			Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of March 31, 2017	(In millions)
As of September 30, 2017													(In millions)
Commodity contracts:
Derivative assets	$	858		$	(732	)	$	(2	)	$	124		$	639		$	(546	)	$	(5	)	$	88
Derivative liabilities	(985		)	732			64			(189		)	(751		)	546			83			(122		)
Total commodity contracts	(127		)	—			62			(65		)	(112		)	—			78			(34		)
Interest rate contracts:
Derivative assets	50			(4		)	—			46			42			(2		)	—			40
Derivative liabilities	(77		)	4			—			(73		)	(78		)	2			—			(76		)
Total interest rate contracts	(27		)	—			—			(27		)	(36		)	—			—			(36		)
Total derivative instruments	$	(154	)	$	—		$	62		$	(92	)	$	(148	)	$	—		$	78		$	(70	)


	Gross Amounts Not Offset in the Statement of Financial Position												Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount			Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of December 31, 2016	(In millions)												(In millions)
Commodity contracts:
Derivative assets	$	1,202		$	(1,005	)	$	(1	)	$	196		$	1,199		$	(1,021	)	$	(13	)	$	165
Derivative liabilities	(1,290		)	1,005			14			(271		)	(1,288		)	1,021			13			(254		)
Total commodity contracts	(88		)	—			13			(75		)	(89		)	—			—			(89		)
Interest rate contracts:
Derivative assets	49			(4		)	—			45			49			(4		)	—			45
Derivative liabilities	(88		)	4			—			(84		)	(88		)	4			—			(84		)
Total interest rate contracts	(39		)	—			—			(39		)	(39		)	—			—			(39		)
Total derivative instruments	$	(127	)	$	—		$	13		$	(114	)	$	(128	)	$	—		$	—		$	(128	)

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 March 31, 2017
Interest Rate Total
(In millions)
Accumulated OCI beginning balance $ (66 ) $ (66 )
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts 3
3
Mark-to-market of cash flow hedge accounting contracts 2
2
Accumulated OCI ending balance, net of $14 tax $ (61 ) $ (61 )
Losses expected to be realized from OCI during the next 12 months, net of $4 tax $ (15 ) $ (15 )


							Interest Rate Contracts
	Three months ended March 31, 2016						Three months ended September 30,						Nine months ended September 30,
	Interest Rate			Total			2017			2016			2017			2016
	(In millions)						(In millions)
Accumulated OCI beginning balance	$	(101	)	$	(101	)	$	(67	)	$	(165	)	$	(66	)	$	(101	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	3			3			4			2			10			12
Mark-to-market of cash flow hedge accounting contracts	(52		)	(52		)	4			32			(3		)	(42		)
Accumulated OCI ending balance, net of $24 tax	$	(150	)	$	(150	)
Accumulated OCI ending balance, net of $15, and $28 tax							$	(59	)	$	(131	)	$	(59	)	$	(131	)
Losses expected to be realized from OCI during the next 12 months, net of $4 tax							$	14					$	14

Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense for interest rate contracts. There was no ineffectiveness for the three and nine months ended ~~March 31,~~September 30, 2017 and 2016.

Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark these derivatives to market through the income statement.

The Company's regression analysis for Marsh Landing, Walnut Creek, and Avra Valley interest rate swaps, while positively correlated, no longer contain match terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated the Marsh Landing, Walnut Creek, and Avra Valley cash flow hedges as of April 28, 2017, and will prospectively mark these derivatives to market through the income statement.

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 March 31,						Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016			2017			2016
Unrealized mark-to-market results	(In millions)						(In millions)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	16		$	(86	)
Reversal of acquired loss/(gain) positions related to economic hedges	2			(13		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges							$	(6	)	$	(30	)	$	19		$	(75	)
Reversal of acquired gain positions related to economic hedges							(2		)	(7		)	(1		)	(11		)
Net unrealized (losses)/gains on open positions related to economic hedges	(24		)	134			(16		)	(50		)	(1		)	27
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(6		)	35			(24		)	(87		)	17			(59		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(15		)	8			(5		)	3			(24		)	13
Net unrealized gains on open positions related to trading activity	1			11
Net unrealized (losses)/gains on open positions related to trading activity							—			(8		)	17			14
Total unrealized mark-to-market (losses)/gains for trading activity	(14		)	19			(5		)	(5		)	(7		)	27
Total unrealized (losses)/gains	$	(20	)	$	54		$	(29	)	$	(92	)	$	10		$	(32	)


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
	2017			2016			2017			2016			2017			2016
	(In millions)						(In millions)
Unrealized gains included in operating revenues	$	114		$	45
Unrealized gains/(losses) included in operating revenues							$	21		$	57		$	178		$	(333	)
Unrealized (losses)/gains included in cost of operations	(134		)	9			(50		)	(149		)	(168		)	301
Total impact to statement of operations — energy commodities	$	(20	)	$	54		$	(29	)	$	(92	)	$	10		$	(32	)
Total impact to statement of operations — interest rate contracts	$	5		$	(11	)	$	11		$	9		$	(8	)	$	(9	)

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.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2017,, the ~~$24~~$1 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of coal, natural gas, ~~coal,~~ and ERCOT ~~electricity~~power due to decreases in coal, natural gas, ~~coal~~ and ERCOT electricity prices, which was largely offset by an increase in value of forward sales of PJM power and New York capacity due to decreases in PJM electricity and New York capacity prices.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2016,, the ~~$134~~$27 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward ~~sales~~purchases of ~~power~~natural gas due to ~~decreases~~increases in ~~electricity prices partially offset by a decrease in value of forward purchases of coal due to decreases in coal~~natural gas prices.

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 ~~March 31,~~September 30, 2017, was ~~$38~~$27 million. The collateral required for contracts with credit rating contingent features as of ~~March 31,~~September 30, 2017, was ~~$33~~$34 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 $417 million as of ~~March 31,~~September 30, 2017.

See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 7 — Impairments

2017 Impairment Losses

Bacliff Project — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to $0 during the second quarter of 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.

Other Impairments — During the second quarter of 2017, the Company recorded impairment losses of approximately $22 million in connection with the Company's Renewables business. During the third quarter of 2017, the Company recorded an additional $14 million in impairment losses, in connection with the Company's Renewable business.

2016 Impairment ~~Loss~~Losses

Rockford — 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.

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 $9 million in impairment 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.

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 2016 Form 10-K. Long-term debt and capital leases consisted of the following:


(In millions, except rates)	March 31, 2017			December 31, 2016			March 31, 2017 interest rate % ^(a)	September 30, 2017			December 31, 2016			September 30, 2017 interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	398		$	398		7.625	$	398		$	398		7.625
Senior notes, due 2021	207			207			7.875	207			207			7.875
Senior notes, due 2022	992			992			6.250	992			992			6.250
Senior notes, due 2023	869			869			6.625	869			869			6.625
Senior notes, due 2024	733			733			6.250	733			733			6.250
Senior notes, due 2026	1,000			1,000			7.250	1,000			1,000			7.250
Senior notes, due 2027	1,250			1,250			6.625	1,250			1,250			6.625
Term loan facility, due 2023	1,886			1,891			L+2.25	1,876			1,891			L+2.25
Revolving credit facility, due 2018 and 2021	125			—			L+2.25
Tax-exempt bonds	455			455			4.125 - 6.00	465			455			4.125 - 6.00
Subtotal NRG recourse debt	7,915			7,795				7,790			7,795
Non-recourse debt:
GenOn senior notes	1,830			1,830			7.875 - 9.875
GenOn Americas Generation senior notes	695			695			8.500 - 9.125
GenOn other	95			96
Subtotal GenOn debt (non-recourse to NRG)	2,620			2,621
NRG Yield Operating LLC Senior Notes, due 2024	500			500			5.375	500			500			5.375
NRG Yield Operating LLC Senior Notes, due 2026	350			350			5.000	350			350			5.000
NRG Yield Inc. Convertible Senior Notes, due 2019	345			345			3.500
NRG Yield Inc. Convertible Senior Notes, due 2020	288			288			3.250
NRG Yield, Inc. Convertible Senior Notes, due 2019								345			345			3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020								288			288			3.250
El Segundo Energy Center, due 2023	414			443			L+1.625 - L+2.25	400			443			L+1.75 - L+2.375
Marsh Landing, due 2017 and 2023	361			370			L+1.750 - L+1.875	334			370			L+1.750 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	965			965			5.696 - 7.015	940			965			5.696 - 7.015
Walnut Creek, term loans due 2023	303			310			L+1.625	279			310			L+1.625
Utah Portfolio, due 2022	287			287			L+2.65	284			287			L+2.625
Tapestry, due 2021	168			172			L+1.625	165			172			L+1.625
CVSR, due 2037	757			771			2.339 - 3.775	746			771			2.339 - 3.775
CVSR HoldCo, due 2037	194			199			4.680	194			199			4.680
Alpine, due 2022	144			145			L+1.750	138			145			L+1.750
Energy Center Minneapolis, due 2017 and 2025	94			96			5.95 - 7.25	82			96			5.95 - 7.25
Energy Center Minneapolis, due 2031	125			125			3.55	125			125			3.55
Viento, due 2023	178			178			L+2.75	169			178			L+3.00
NRG Yield - other	578			540			various	562			540			various
Subtotal NRG Yield debt (non-recourse to NRG)	6,051			6,084				5,901			6,084
Ivanpah, due 2033 and 2038	1,108			1,113			2.285 - 4.256	1,097			1,113			2.285 - 4.256
Carlsbad Energy Project								407			—			4.120
Agua Caliente, due 2037	846			849			2.395 - 3.633	833			849			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	89			—			5.430	89			—			5.430
Cedro Hill, due 2025	161			163			L+1.75	153			163			L+1.75
Midwest Generation, due 2019	213			231			4.390	173			231			4.390
NRG Other	462			468			various	689			468			various
Subtotal other NRG non-recourse debt	2,879			2,824				3,441			2,824
Subtotal all non-recourse debt	11,550			11,529				9,342			8,908
Subtotal long-term debt (including current maturities)	19,465			19,324				17,132			16,703
Capital leases	12			8			various	6			6			various
Subtotal long-term debt and capital leases (including current maturities)	19,477			19,332				17,138			16,709
Less current maturities	(1,688		)	(1,220		)		(1,247		)	(516		)
Less debt issuance costs	(191		)	(188		)		(198		)	(188		)
Premiums, net of discounts	74			82
Discounts								(35		)	(48		)
Total long-term debt and capital leases	$	17,672		$	18,006			$	15,658		$	15,957

(a) As of ~~March 31,~~September 30, 2017, L+ equals 3 month LIBOR plus x%, with the exception of the ~~Viento Funding II term loan, the~~ Utah Portfolio term ~~loans, the Alpine Term Loan, the NRG Marsh Landing term loan, the Walnut Creek term loan, the 2023 Term Loan Facility, and the Revolving credit facility which are 1 month LIBOR plus x%.~~loans.

Recourse Debt

~~Revolving Credit Facility~~

On January 27, 2017, GenOn Mid-Atlantic entered into an agreement with Natixis Funding Corp., or Natixis, under which Natixis will procure payment and credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. GenOn Mid-Atlantic made a payment of $130 million plus fees of $1 million as consideration for Natixis applying for the issuance of, and obtaining, letters of credit from Natixis, New York Branch, the LC Provider, to support the lease payments. Natixis is solely responsible for (i) obtaining letters of credit from the LC Provider, (ii) causing the letters of credit to be issued to the lessors to support the lease payments on behalf of GenOn Mid-Atlantic, (iii) making lease payments and (iv) satisfying any reimbursement obligations payable to the LC Provider. The payment is reflected as a long-term deposit on the Company's consolidated balance sheet as of March 31, 2017.

On February 24, 2017, GenOn Mid-Atlantic received a series of notices from certain of the owner lessors under its operating leases of the Morgantown coal generation unit alleging default, or Notices. The Notices allege the existence of lease events of default as a result of, among other items, the purported failure by GenOn Mid-Atlantic to comply with a covenant requiring the maintenance of qualifying credit support. The Notices instructed the relevant trustees to draw on letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn, supporting the GenOn Mid-Atlantic operating leases that were set to expire on February 28, 2017. The offset was recorded to other non-current assets under the related operating leases pending resolution of the matter which is further described below. On February 28, 2017, the trustees drew on the letters of credit under NRG's revolving credit facility, which resulted in borrowings of $125 million. Upon notification, GenOn became obligated under the secured intercompany revolving credit agreement between NRG and GenOn. GenOn requested Genon Mid-Atlantic repay the related amount borrowed under the secured intercompany revolving credit agreement. GenOn Mid-Atlantic is unaware of whether any further action will be taken by the owner lessors or any other person in connection with the Notices. GenOn Mid-Atlantic disagrees with the owner lessors as to the existence of any lease events of default and/or any breaches by GenOn Mid-Atlantic of any terms and conditions of the operating leases and believes that the declaration of a lease event of default, the instruction to draw on the letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn and the draws thereon constituted a violation by the owner lessors and the relevant trustees of the terms and conditions of the GenOn Mid-Atlantic operating leases. GenOn Mid-Atlantic intends to vigorously pursue its rights and remedies in connection with these actions. On March 7, 2017, GenOn Mid-Atlantic filed a complaint in the Supreme Court for the State of New York against the owner lessors of the Morgantown and Dickerson facilities and U.S. Bank National Association in its capacity as the indenture trustee. The complaint seeks, ~~inter alia~~, a declaratory judgment that no lease events of default exist and asserts counts for breach of contract, conversion, tortious interference, breach of the implied covenant of good faith and fair dealing, unjust enrichment, constructive trust, and injunctive relief. The defendants in this action have not yet responded to the complaint and have until June 5, 2017 to do so. The court has set an initial conference hearing for June 12, 2017.

2023 Term Loan Facility

On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. The LIBOR floor remains 0.75%.

Revolving Credit Facility

On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, no cash borrowings were outstanding on the revolver.

Senior Notes

2017 Senior Note Redemptions

2016 Senior Note 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.

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.

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.

Non-recourse Debt

~~GenOn Senior Notes~~

~~As disclosed in Note 1,~~ ~~Basis of Presentation~~, as of March 31, 2017, $691 million of GenOn's Senior Notes, excluding $4 million of associated premiums, of GenOn's Senior Notes outstanding are classified as current within the consolidated balance sheet as they mature on June 15, 2017. 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. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is not expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern.

During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. 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 ~~March 31,~~September 30, 2017, there was ~~$64~~$68 million of letters of credit issued under the revolving credit facility and no borrowing outstanding on the revolver.

Project Financings

Agua Caliente Project Financing

On February 17, 2017, Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC, or Agua Caliente Holdco, the indirect owners of 51% of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.

Carlsbad Project Financing

On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.

Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letter of credit facility with an aggregate principle amount not to exceed $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.

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 $~~104~~102 million as of ~~March 31,~~September 30, 2017.

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 2016 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to ~~$88~~$100 million as of ~~March 31,~~September 30, 2017, 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)	March 31, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Current assets	$	90	$	87	$	74	$	87
Net property, plant and equipment	1,513		1,534		1,466		1,534
Other long-term assets	948		954		1,026		954
Total assets	2,551		2,575		2,566		2,575
Current liabilities	59		59		69		59
Long-term debt	439		442		420		442
Other long-term liabilities	185		183		187		183
Total liabilities	683		684		676		684
Noncontrolling interests	535		529		578		529
Net assets less noncontrolling interests	$	1,333	$	1,362	$	1,312	$	1,362

Note 10 — Changes in Capital Structure

As of ~~March 31,~~September 30, 2017 and December 31, 2016, 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	Issued	Treasury		Outstanding
Balance as of December 31, 2016	417,583,825	(102,140,814	)	315,443,011	417,583,825	(102,140,814	)	315,443,011
Shares issued under LTIPs	355,047	—		355,047	634,738	—		634,738
Shares issued under ESPP	—	282,530		282,530	—	560,769		560,769
Balance as of March 31, 2017	417,938,872	(101,858,284	)	316,080,588
Balance as of September 30, 2017					418,218,563	(101,580,045	)	316,638,518

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.

Amended and Restated Employee Stock Purchase Plan

~~As of March 31, 2017, there were 385,289 shares of treasury stock available for issuance under the ESPP.~~ On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the ESPP. As of September 30, 2017, there were 3,107,050 shares of treasury stock available for issuance under the ESPP.

Amended and Restated Long-term Incentive Plan

On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the NRG Energy, Inc. Amended and Restated Long-term Incentive Plan.

NRG Common Stock Dividends

The following table lists the dividends paid during the ~~three~~nine months ended ~~March 31,~~September 30, 2017:

First Quarter 2017
Dividends per Common Share $ 0.030



	Third Quarter 2017		Second Quarter 2017		First Quarter 2017
Dividends per Common Share	$	0.03	$	0.03	$	0.03

On ~~April 7,~~October 18, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable ~~May~~November 15, 2017, to stockholders of record as of ~~May~~November 1, 2017, 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. During the second quarter of 2016, the Company repurchased 100% of the outstanding shares of its 2.822% preferred stock. The reconciliation of NRG's basic and diluted earnings/(loss) per share is shown in the following table:


	Three months ended March 31,					Three months ended September 30,				Nine months ended September 30,
(In millions, except per share data)	2017			2016		2017		2016		2017			2016
Basic (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
Net (loss)/income attributable to NRG Energy, Inc.	$	(163	)	$	82
Basic and diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders						Basic and diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.						$	171	$	402	$	(619	)	$	213
Dividends for preferred shares	—			5		—		—		—			5
(Loss)/income available for common stockholders	$	(163	)	$	77
Gain on redemption of 2.822% redeemable perpetual preferred stock						—		—		—			(78		)
Income/(loss) available for common stockholders						$	171	$	402	$	(619	)	$	286
Weighted average number of common shares outstanding - basic	316			315		317		316		317			315
(Loss)/Earnings per weighted average common share — basic	$	(0.52	)	$	0.24
Diluted (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
Income/(loss) per weighted average common share — basic						$	0.54	$	1.27	$	(1.95	)	$	0.91
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders						Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted	316			315		317		316		317			315
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—			—		5		1		—			1
Total dilutive shares	316			315		322		317		317			316
(Loss)/earnings per weighted average common share — diluted	$	(0.52	)	$	0.24
Income/(loss) per weighted average common share — diluted						$	0.53	$	1.27	$	(1.95	)	$	0.91

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~~earnings/(loss) per share:


	Three months ended March 31,		Three months ended September 30,		Nine months ended September 30,
(In millions of shares)	2017	2016	2017	2016	2017	2016
Equity compensation plans	6	4	1	2	6	3
Embedded derivative of 2.822% redeemable perpetual preferred stock	—	16
Total	6	20	1	2	6	3

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, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. ~~Intersegment sales are accounted for at market prices.~~ The financial information for the three and nine months ended ~~March 31,~~September 30, 2016 has been recast to reflect the current segment structure.

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 March 27, 2017, NRG Yield acquired from NRG a 16% interest in the Agua Caliente solar project, and NRG's interests in seven utility-scale solar projects located in Utah. ~~Both~~On August 1, 2017, NRG Yield acquired the remaining 25% interest in NRG Wind TE Holdco from the Company. All three 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.

On June 14, 2017, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods have been recast to reflect the deconsolidation of GenOn and to present discontinued operations within the corporate segment.

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).



	Generation^(a)			Retail ^(a)		Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Three months ended September 30, 2017	(In millions)
Operating revenues^(a)	$	1,224		$	1,937	$	144		$	265	$	2		$	(523	)	$	3,049
Depreciation and amortization	96			29		51			88		8			—			272
Impairment losses	1			—		13			—		—			—			14
Equity in (losses)/earnings of unconsolidated affiliates	12			—		(3		)	28		—			(10		)	27
Loss on debt extinguishment, net	—			—		—			—		(1		)	—			(1		)
Income/(loss) from continuing operations before income taxes	258			69		(7		)	49		(161		)	(12		)	196
Income/(loss) from continuing operations	258			69		(4		)	41		(162		)	(12		)	190
Loss from discontinued operations, net of tax	—			—		—			—		(27		)	—			(27		)
Net Income/(loss)	258			69		(4		)	41		(189		)	(12		)	163
Net Income/(loss) attributable to NRG Energy, Inc.	$	258	—	$	69	$	9		$	35	$	(220	)	$	20		$	171
Total assets as of September 30, 2017	$	8,585		$	2,445	$	5,357		$	8,442	$	11,090		$	(10,449	)	$	25,470



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	491	$	(8	)	$	19	$	—	$	21	$	—	$	523



	Generation^(a)		Retail^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Three months ended September 30, 2016	(In millions)
Operating revenues^(a)	$	1,536	$	2,012		$	139		$	272	$	24		$	(562	)	$	3,421
Depreciation and amortization	134		26			48			75		15			—			298
Impairment losses	9		—			—			—		—			—			9
Equity in earnings/(losses) of unconsolidated affiliates	6		—			(10		)	16		5			(1		)	16
Gain on sale of assets			—			—			—		4			—			4
Loss on debt extinguishment, net	—		—			—			—		(50		)	—			(50		)
Income/(loss) from continuing operations before income taxes	370		(78		)	(1		)	63		(202		)	4			156
Income/(loss) from continuing operations	372		(78		)	2			50		(222		)	4			128
Income from discontinued operations, net of tax	—		—			—			—		265			—			265
Net Income/(Loss)	372		(78		)	2			50		43			4			393
Net Income/(Loss) attributable to NRG Energy, Inc.	$	372	$	(78	)	$	(9	)	$	55	$	19		$	43		$	402



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	506	$	(2	)	$	8	$	—	$	50	$	52	$	—	$	562

Generation^(a)

Retail ^(a)

Renewables^(a)(b)
NRG Yield
Corporate^(a)
Eliminations Total
Three months ended March 31, 2017 (In millions)
Operating revenues^(a)
$ 1,343
$ 1,335
$ 98
$ 218
$ 8
$ (243 ) $ 2,759
Depreciation and amortization 138
28
49
75
10
—
300
Equity in (losses)/earnings of unconsolidated affiliates (13 ) —
(1 ) 19
3
(3 ) 5
Gain on sale of assets 2
—
—
—
—
—
2
Income/(loss) before income taxes 67
(30 ) (37 ) (2 ) (203 ) (2 ) (207 )
Net Income/(Loss) 67
(33 ) (31 ) (1 )
(203 ) (2 ) (203 )
Net Income/(Loss) attributable to NRG Energy, Inc. $ 67
$ (32 ) $ (3 ) $ 13
$ (203 ) $ (5 ) $ (163 )
Total assets as of March 31, 2017 $ 12,962
$ 2,150
$ 5,123
$ 8,580
$ 14,621
$ (14,016 ) $ 29,420



	Generation^(a)			Retail ^(a)		Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Nine months ended September 30, 2017	(In millions)
Operating revenues^(a)	$	3,072		$	4,875	$	364		$	767	$	13		$	(959	)	$	8,132
Depreciation and amortization	287			87		150			241		24			—			789
Impairment losses	42			—		35			—		—			—			77
Equity in (losses)/earnings of unconsolidated affiliates	(16		)	—		(6		)	63		7			(19		)	29
Gain on sale of assets	4			—		—			—		—			—			4
Loss on debt extinguishment, net	—			—		(3		)	—		—			—			(3		)
Income/(loss) from continuing operations before income taxes	202			371		(97		)	100		(430		)	(21		)	125
Income/(loss) from continuing operations	200			380		(84		)	85		(440		)	(21		)	120
Loss from discontinued operations, net of tax	—			—		—			—		(802		)	—			(802		)
Net Income/(Loss)	200			380		(84		)	85		(1,242		)	(21		)	(682		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	200		$	380	$	(18	)	$	87	$	(1,306	)	$	38		$	(619	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	897	$	3	$	23	$	—	$	36	$	—	$	959

(a) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 205
$ 1
$ 8
$ —
$ 29
$ —
$ 243
(b) Includes loss on debt extinguishment $ —
$ —
$ (2 ) $ —
$ —
$ —
$ (2 )



	Generation^(a)			Retail^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)			Eliminations			Total
Nine months ended September 30, 2016	(In millions)
Operating revenues^(a)	$	3,173		$	4,918	$	336		$	789	$	54		$	(942	)	$	8,328
Depreciation and amortization	331			83		143			224		45			—			826
Impairment losses	26			—		27			—		12			—			65
Equity in earnings/(losses) of unconsolidated affiliates	1			—		(16		)	34		11			(17		)	13
Loss on sale of assets	—			—		—			—		(79		)	—			(79		)
Impairment loss on investment	(142		)	—		1			—		(6		)	—			(147		)
Loss on debt extinguishment, net	—			—		—			—		(119		)	—			(119		)
(Loss)/income from continuing operations before income taxes	(51		)	735		(121		)	141		(706		)	(15		)	(17		)
(Loss)/income from continuing operations	(49		)	734		(107		)	116		(771		)	(15		)	(92		)
Income from discontinued operations, net of tax	—			—		—			—		256			—			256
Net (Loss)/Income	(49		)	734		(107		)	116		(515		)	(15		)	164
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(49	)	$	734	$	(103	)	$	113	$	(547	)	$	65		$	213



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	836	$	3	$	16	$	6	$	81	$	—	$	942

Generation^(a)

Retail^(a)

Renewables^(a)

NRG Yield^(a)

Corporate^(a)(b)
Eliminations Total
Three months ended March 31, 2016 (In millions)
Operating revenues^(a)
$ 1,708
$ 1,370
$ 96
$ 234
$ 18
$ (197 ) $ 3,229
Depreciation and amortization 144
30
48
74
17
—
313
Impairment losses (137 ) —
—
—
(9 ) —
(146 )
Equity in earnings/(loss) of unconsolidated affiliates (8 ) —
(4 ) 4
3
(2 ) (7 )
Gain on sale of assets 32
—
—
—
—
—
32
Income/(Loss) before income taxes 191
150
(46 ) 2
(231 ) 2
68
Net Income/(Loss) 191
150
(40 ) 2
(258 ) 2
47
Net Income/(Loss) attributable to NRG Energy, Inc. $ 191
$ 150
$ (30 ) $ 10
$ (245 ) $ 6
$ 82

(a) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 118
$ 3
$ 6
$ 4
$ 66
$ —
$ 197
(b) Includes gain on debt extinguishment $ —
$ —
$ —
$ —
$ 11
$ —
$ 11

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
(In millions except otherwise noted)	2017			2016			2017			2016			2017			2016
Income/(loss) before income taxes	$	(207	)	$	68
Income tax (benefit)/expense	(4		)	21
Income/(Loss) before income taxes							$	196		$	156		$	125		$	(17	)
Income tax expense from continuing operations							6			28			5			75
Effective tax rate	1.9		%	30.9		%	3.1		%	17.9		%	4.0		%	(441.2		)%

For the three months and nine months ended ~~March 31,~~September 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance ~~partially offset by~~and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.

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 tax benefit for the change in valuation allowance, partially offset by amortization of indefinite lived assets, inclusion of consolidated partnerships and state tax expense.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to ~~the change in the valuation allowance, partially offset by the recording of a deferred tax liability associated with~~ the amortization of indefinite lived ~~assets.~~assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.

Uncertain Tax Benefits

As of ~~March 31,~~September 30, 2017,, NRG has recorded a non-current tax liability of ~~$38~~$40 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the ~~three~~nine months ended ~~March 31,~~September 30, 2017, NRG accrued ~~$0.2 million~~an immaterial amount of interest relating to the uncertain tax benefits. As of ~~March 31,~~September 30, 2017, NRG had cumulative interest and penalties related to these uncertain tax benefits of $34 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 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

Note 14 — Related Party Transactions

Services Agreement with GenOn

The Company provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million through the pendency of the Chapter 11 Cases. Beginning on June 14, 2017, NRG records operating income for the amounts earned for shared services of approximately $5 million per month. Subsequent to the GenOn Entities' emergence from bankruptcy, NRG will provide shared services for two months at no charge; after which GenOn has an additional two, one-month options to provide services at an annualized fee of $84 million. NRG charges these fees on a monthly basis, less amounts incurred directly by GenOn. For the three and nine months ended September 30, 2017, NRG recorded other income - affiliate related to these services of $14 million and $104 million, respectively. For the three and nine months ended September 30, 2016, NRG recorded other income - affiliate related to these services of $48 million and $144 million, respectively.

In addition, as described in Note 3, Discontinued Operations, Dispositions and Acquisitions, under the Restructuring Support Agreement, NRG has agreed to provide GenOn with a $28 million credit against amounts owed to NRG prior to the Petition Date under the current Services Agreement. The credit was intended to reimburse GenOn for its payment of financing costs. In addition, the Restructuring Support Agreement provides that to the extent GenOn has paid for services during the bankruptcy proceedings and the aforementioned credit has not been applied in full, NRG shall, upon request by GenOn, reimburse such payments in cash up to the amount of any unused portion of the credit.

See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement and Services Agreement, based on which NRG recorded a reserve of $15 million against affiliate receivable balances as of September 30, 2017.

Credit Agreement with GenOn

NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At September 30, 2017 and December 31, 2016, $103 million and $272 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of September 30, 2017, there were $125 million of loans outstanding under the intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under this intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of September 30, 2017, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. In addition, NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. The letter of credit facility provided availability of up to $330 million less amounts borrowed and letters of credit provided are required to be cash collateralized at 103% of the letter of credit amount. On July 27, 2017, this letter of credit facility was terminated as GenOn has obtained a separate letter of credit facility with a third party financial institution. Effective with completion of the reorganization, GenOn must repay NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of September 30, 2017. Interest continues to accrue during the pendency of the Chapter 11 Cases and borrowings remain secured obligations.

Commercial Operations Agreement

NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of September 30, 2017, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively.

Note 1415 — Commitments and Contingencies

This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2016 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 ~~March 31,~~September 30, 2017, hedges under the first liens were out-of-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 plant 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. In January 2017, the Company and PG&E executed amendments to the PPAs that provide, among other things, the ability to cure any failure to meet the guaranteed energy production amounts through performance and liquidated damage provisions. On February 2, 2017, PG&E filed a request with the CPUC to approve the amendments. On April 5, 2017, the CPUC issued a draft resolution proposing approval of the amendments without modification. Pending final and nonappealable CPUC approval, PG&E agreed to refrain from declaring any event of default with respect to any failure to deliver the guaranteed energy production amounts.

Lignite Contract with Texas Westmoreland Coal Co. — The Company has a contract with TWCC for reclamation activities associated with closure of the Jewett mine. 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.

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. The Company believes that it has established an adequate reserve for these cases.

~~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 and was argued before the Fifth Circuit on February 8, 2017.

~~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, or 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 Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. 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 U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. 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 March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification.

In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. On March 28, 2017, plaintiffs filed their appellate brief. 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 U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.

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. ~~The Company does not expect~~On August 28, 2017, the ~~resolution~~parties entered into an Assurance of Discontinuance resolving this ~~matter to have a material impact on the Company's consolidated financial position, results of operation, or cash flows.~~matter.

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.

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 June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants’ filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, Defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending the New Jersey settlement. On July 12, 2017, the parties in the New Jersey action reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed their motion for preliminary approval of the class settlement.

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 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. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the demurrers without leave to amend. On July 14, 2017, CDWR filed a notice of appeal.

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. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On October 26, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on December 6, 2017 and defendants' reply is due on February 8, 2018.

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 a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017.

Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which the court denied. On August 22, 2017, NRG filed a notice of appeal. NRG’s appellate brief was filed on October 25, 2017. Plaintiffs’ opposition is due on November 16, 2017.

Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answer and affirmative defenses.

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed a motion for a more definite statement on September 18, 2017.

GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them has agreed to support Bankruptcy Court approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. Moreover, the Bankruptcy Court may not approve the plan of reorganization. If the plan of reorganization is not approved, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remain subject to any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Discontinued Operations, Dispositions and Acquisitions, for additional information related to the Chapter 11 Cases.

GenOn Noteholders' Lawsuit —On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. Pursuant to the terms of the Restructuring Support Agreement, this matter should ultimately be resolved if the GenOn Entities' plan of reorganization is approved by the Bankruptcy Court.

Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. A claims estimation ruling on this matter by the Bankruptcy Court could occur as early as November 7, 2017.

BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas. On January 15, 2013, the parties entered into a Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas. The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016. But even a year later, BTEC had not satisfied all of the contractually-required acceptance criteria. As a result and given that the MIPA expiration date passed on May 31, 2017, NRG elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties. In addition, BTEC seeks damages, interest and attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million.

GenOn Related Contingencies

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. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. On January 17, 2018, the bankruptcy court will hear a Motion for a Final Decree in the Mirant bankruptcy.

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, or 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 Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. 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 U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. 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 March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification. On June 13, 2017, the Ninth Circuit granted plaintiffs' petition for interlocutory review.

In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. The appeal has been fully briefed by the parties. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.

Potomac River Environmental Investigation—In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, 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 Potomac River LLC 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. Class certification hearings are scheduled on August 21, 2017 and June 19, 2017 in the New Jersey and California cases respectively.

~~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. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the demurrers without leave to amend.

~~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. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017.

~~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 a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The Defendants' reply was filed on March 24, 2017. Oral argument is scheduled for June 20, 2017.

~~GenOn Noteholders' Lawsuit~~ —On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to a services agreement between NRG and GenOn. Plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the management services agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On March 31, 2017, NRG and GenOn filed separate motions to dismiss the complaint, but such motions are superseded by the amended complaint.

~~Griffoul v. NRG Residential Solar Solutions~~ — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits.

~~Rice v. NRG~~ — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from the Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property.

Note 1516 — Regulatory Matters

This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2016 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.

National

Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, ~~the~~ Illinois ~~legislature approved~~enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day. Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. ~~The~~On July 14, 2017, Defendants' motions ~~are pending before~~to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. ~~District Court.~~Court of Appeals for the Seventh Circuit. On July 18, 2017, the Court of Appeals issued an order setting an expedited briefing schedule for the matter. Briefing is underway.

Zero-Emission Credits for Nuclear Plants in New York — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which 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. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, 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. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants. On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. On September 9, 2017, the Court of Appeals issued a briefing schedule. Briefing is underway.

~~Current Administration and Changeover at FERC~~Department of Energy's Proposed Grid Resiliency Pricing Rule — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC ~~is currently without~~to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a ~~quorum~~notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and ~~cannot issue orders~~capacity markets in ~~contested proceedings until~~ a new Commissioner is appointed. FERC continues to issue orders through authority that was delegated by the full Commission to FERC Staff. The legal validity of these actions has been questioned in connectionmanner compatible with ~~several of those orders. With a new administration and three vacant positions at FERC, NRG’s business may be affected because its generation fleet is subject to changes in FERC regulatory policy.~~robust competitive markets.

Note 1617 — Environmental Matters

This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2016 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. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the ~~new~~current U.S. presidential administration, some of these rules are being reconsidered and reviewed. 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. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the ~~new~~current U.S. presidential administration.

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) SO₂ budgets for four states including Texas and (ii) ozone-season NOx 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. This rule has been challenged in the D.C. Circuit. 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 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. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. 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.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control. The Company estimated that it would have cost approximately $200 million over the next eight years (the majority of the cost would be incurred after 2019) to comply with this rule at 11 coal-fired plants. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. ~~This regulation also has been challenged.~~On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The ~~Company expects the~~ legal challenges ~~to be~~have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company ~~expects to reduce~~has largely eliminated its estimate of the environmental capital expenditures that would behave been required to comply with permits ~~issued that incorporate~~incorporating the revised guidelines. The Company ~~decides to invest capital for environmental controls based on:~~will revisit these estimates after the certainty of regulations; evaluation of different technologies; options to convert to gas; and the expected economic returns on the capital. Over the next several years, the Company will decide whether to proceed with these investments at each of the plants as permits are renewed based on, among other things, the legal certainty of the regulation and market conditions at that time.rule is revised.

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. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. 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 ~~March 31,~~September 30, 2017.

East Region

Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program, or the VCP. On February 4, 2008, DNREC issued findings that no further action was required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. In the second quarter of 2017, the Company completed the remediation requirements in the remediation plan. The cost of completing the work required by the ~~approved~~ remediation plan ~~is consistent with~~was within amounts budgeted in early ~~2016 and on track for completion in the second quarter of 2017.~~2016. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.

In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is working with DNREC and other trustees to close out the assessment process.

Note 1718 — Condensed Consolidating Financial Information

As of ~~March 31,~~September 30, 2017, the Company had outstanding $5.4 billion of Senior Notes due from 2018 to 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 ~~March 31,~~September 30, 2017:



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

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.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended ~~March 31,~~September 30, 2017

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	1,599		$	1,243		$	—		$	(83	)	$	2,759		$	2,160		$	1,021		$	—		$	(132	)	$	3,049
Operating Costs and Expenses
Cost of operations	1,261			933			14			(83		)	2,125			1,588			682			15			(129		)	2,156
Depreciation and amortization	102			190			8			—			300			104			160			8			—			272
Impairment losses																—			14			—			—			14
Selling, general and administrative	96			106			70			—			272			97			29			88			(1		)	213
Reorganization																—			—			18			—			18
Development activity expenses	—			12			5			—			17			—			9			5						14
Total operating costs and expenses	1,459			1,241			97			(83		)	2,714			1,789			894			134			(130		)	2,687
Gain on sale of assets	2			—			—			—			2
Other income - affiliate																—			—			14			—			14
Operating Income/(Loss)	142			2			(97		)	—			47			371			127			(120		)	(2		)	376
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(77		)	(34		)	67			44			—
Equity in losses of consolidated subsidiaries																(41		)	(9		)	(134		)	184			—
Equity in (losses)/earnings of unconsolidated affiliates	(1		)	7			(1		)	—			5			—			(606		)	666			(33		)	27
Other income	1			8			4			(1		)	12			7			3			5			—			15
Loss on debt extinguishment	—			(2		)	—			—			(2		)	—			(1		)	—			—			(1		)
Interest expense	(4		)	(151		)	(114		)	—			(269		)	(4		)	(103		)	(114		)	—			(221		)
Total other expense	(81		)	(172		)	(44		)	43			(254		)
Income/(Loss) Before Income Taxes	61			(170		)	(141		)	43			(207		)
Total other (expense)/income																(38		)	(716		)	423			151			(180		)
Income/(Loss) from Continuing Operations Before Income Taxes																333			(589		)	303			149			196
Income tax expense/(benefit)	19			(46		)	25			(2		)	(4		)	113			(209		)	102			—			6
Income/(Loss) from Continuing Operations																220			(380		)	201			149			190
Loss from Discontinued Operations, net of income tax																—			(27		)	—			—			(27		)
Net Income/(Loss)	42			(124		)	(166		)	45			(203		)	220			(407		)	201			149			163
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	—			(38		)	(3		)	1			(40		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests																—			(3		)	30			(35		)	(8		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	42		$	(86	)	$	(163	)	$	44		$	(163	)	$	220		$	(404	)	$	171		$	184		$	171


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the nine months ended September 30, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	5,517		$	2,872		$	—		$	(257	)	$	8,132
Operating Costs and Expenses
Cost of operations	4,156			1,904			46			(254		)	5,852
Depreciation and amortization	307			458			24			—			789
Impairment losses	42			35			—			—			77
Selling, general and administrative	281			115			304			(3		)	697
Reorganization	—			—			18			—			18
Development activity expenses	—			34			15			—			49
Total operating costs and expenses	4,786			2,546			407			(257		)	7,482
Other income - affiliate	—			—			104			—			104
Gain on sale of assets	4			—			—			—			4
Operating Income/(Loss)	735			326			(303		)	—			758
Other Income/(Expense)
Equity in losses of consolidated subsidiaries	(61		)	(66		)	(182		)	309			—
Equity in earnings/(losses) of unconsolidated affiliates	—			101			(3		)	(69		)	29
Other income	8			15			10			—			33
Loss on debt extinguishment	—			(3		)	—			—			(3		)
Interest expense	(11		)	(328		)	(353		)	—			(692		)
Total other expense	(64		)	(281		)	(528		)	240			(633		)
Income/(Loss) from Continuing Operations Before Income Taxes	671			45			(831		)	240			125
Income tax expense/(benefit)	244			28			(267		)	—			5
Income/(Loss) from Continuing Operations	427			17			(564		)	240			120
Loss from Discontinued Operations, net of income tax	—			(802		)	—			—			(802		)
Net Income/(Loss)	427			(785		)	(564		)	240			(682		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(49		)	55			(69		)	(63		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	427		$	(736	)	$	(619	)	$	309		$	(619	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the three months ended ~~March 31,~~September 30, 2017

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)														(In millions)
Net Income/(Loss)	$	42	$	(124	)	$	(166	)	$	45		$	(203	)	$	220	$	(407	)	$	201		$	149		$	163
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	—		5			4			(5		)	4			—		7			7			(7		)	7
Foreign currency translation adjustments, net	5		4			7			(9		)	7			2		2			2			(4		)	2
Available-for-sale securities, net															—		—			1			—			1
Defined benefit plans, net	—		1			(1		)	—			—			—		—			(2		)	1			(1		)
Other comprehensive income	5		10			10			(14		)	11			2		9			8			(10		)	9
Comprehensive Income/(Loss)	47		(114		)	(156		)	31			(192		)	222		(398		)	209			139			172
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest	—		(37		)	(3		)	1			(39		)
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest															—		—			30			(35		)	(5		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	47		(77		)	(153		)	30			(153		)	$	222	$	(398	)	$	179		$	174		$	177
Comprehensive Income/(Loss) Available for Common Stockholders	$	47	$	(77	)	$	(153	)	$	30		$	(153	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the nine months ended September 30, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	427	$	(785	)	$	(564	)	$	240		$	(682	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	—		6			7			(7		)	6
Foreign currency translation adjustments, net	7		7			9			(13		)	10
Available-for-sale securities, net	—		—			2			—			2
Defined benefit plans, net	—		29			25			(28		)	26
Other comprehensive income	7		42			43			(48		)	44
Comprehensive Income/(Loss)	434		(743		)	(521		)	192			(638		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(47		)	55			(69		)	(61		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	434	$	(696	)	$	(576	)	$	261		$	(577	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~March 31, 2017~~

~~(Unaudited)~~

Guarantor Subsidiaries Non-Guarantor Subsidiaries
NRG Energy, Inc.
(Note Issuer)

Eliminations^(a)
Consolidated
ASSETS (In millions)
Current Assets
Cash and cash equivalents $ —
$ 1,257
$ 256
$ —
$ 1,513
Funds deposited by counterparties 3
—
—
—
3
Restricted cash 5
392
—
—
397
Accounts receivable - trade, net 592
378
4
—
974
Accounts receivable - affiliate 251
23
(36 ) (231 ) 7
Inventory 483
657
—
—
1,140
Derivative instruments 594
207
3
(122 ) 682
Cash collateral paid in support of energy risk management activities 173
104
—
—
277
Prepayments and other current assets 94
295
58
—
447
Total current assets 2,195
3,313
285

(353 ) 5,440
Net property, plant and equipment 4,168
13,555
246
(27 ) 17,942
Other Assets
Investment in subsidiaries 1,067
1,062
10,040
(12,169 ) —
Equity investments in affiliates —
1,144
4
—
1,148
Notes receivable, less current portion —
13
125
(125 ) 13
Goodwill 359
303
—
—
662
Intangible assets, net 566
1,394
—
(3 ) 1,957
Nuclear decommissioning trust fund 627
—
—
—
627
Derivative instruments 178
66
34
(52 ) 226
Deferred income tax (2 ) 911
(686 ) —
223
Non-current assets held-for-sale —
10
—
—
10
Other non-current assets 71
1,037
64
—
1,172
Total other assets 2,866
5,940
9,581
(12,349 ) 6,038
Total Assets $ 9,229
$ 22,808
$ 10,112
$ (12,729 ) $ 29,420
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases $ —
$ 1,268
$ 420
$ —
$ 1,688
Accounts payable 436
403
33
—
872
Accounts payable — affiliate 738
1,686
(2,193 ) (231 ) —
Derivative instruments 584
285
—
(122 ) 747
Cash collateral received in support of energy risk management activities 3
—
—
—
3
Accrued expenses and other current liabilities 251
368
268
—
887
Total current liabilities 2,012
4,010
(1,472 ) (353 ) 4,197
Other Liabilities
Long-term debt and capital leases 244
10,443
7,110
(125 ) 17,672
Nuclear decommissioning reserve 291
—
—
—
291
Nuclear decommissioning trust liability 352
—
—
—
352
Deferred income taxes 200
(1,095 ) 915
—
20
Derivative instruments 183
184
—
(52 ) 315
Out-of-market contracts, net 77
940
—
—
1,017
Non-current liabilities held-for-sale —
12
—
—
12
Other non-current liabilities 402
763
322
—
1,487
Total non-current liabilities 1,749
11,247
8,347
(177 ) 21,166
Total liabilities 3,761
15,257
6,875
(530 ) 25,363
Redeemable noncontrolling interest in subsidiaries —
44
—
—
44
Stockholders’ Equity 5,468
7,507
3,237
(12,199 ) 4,013
Total Liabilities and Stockholders’ Equity $ 9,229
$ 22,808
$ 10,112
$ (12,729 ) $ 29,420


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

~~NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED~~

~~CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~For the three months ended March 31, 2017 (Unaudited)~~

Guarantor Subsidiaries Non-Guarantor Subsidiaries
NRG Energy, Inc.
(Note Issuer)

Eliminations^(a)
Consolidated
(In millions)
Cash Flows from Operating Activities
Net income/(loss) $ 42
$ (124 ) $ (166 ) $ 45
$ (203 )
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates —
18
—
(5 ) 13
Equity in losses/(earnings) of unconsolidated affiliates 1
(7 ) 1
—
(5 )
Depreciation and amortization 102
190
8
—
300
Provision for bad debts 8
1
—
—
9
Amortization of nuclear fuel 12
—
—
—
12
Amortization of financing costs and debt discount/premiums —
(3 ) 4
—
1
Amortization of intangibles and out-of-market contracts 6
4
—
—
10
Amortization of unearned equity compensation —
—
8
—
8
Changes in deferred income taxes and liability for uncertain tax benefits 19
(46 ) 28
—
1
Changes in nuclear decommissioning trust liability 36
—
—
—
36
Changes in derivative instruments (4 ) 30
(1 ) —
25
Changes in collateral deposits supporting energy risk management activities (136 ) 62
—
—
(74 )
Gain on sale of assets (2 ) —
—
—
(2 )
Cash (used)/provided by changes in other working capital (86 ) 499
(604 ) (8 ) (199 )
Net Cash (Used)/Provided by Operating Activities (2 ) 624
(722 ) 32
(68 )
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc. —
—
22
(22 ) —
Acquisition of Drop Down Assets, net of cash acquired —
(131 ) —
131
—
Intercompany dividends —
—
129
(129 ) —
Acquisition of business, net of cash acquired —
(3 ) —
—
(3 )
Capital expenditures (64 ) (200 ) (4 ) —
(268 )
Decrease in restricted cash, net 2
11
—
—
13
Decrease in restricted cash - U.S. DOE projects 4
32
—
—
36
Decrease in notes receivable —
4
—
—
4
Purchases of emission allowances (9 ) —
—
—
(9 )
Proceeds from sale of emission allowances 11
—
—
—
11
Investments in nuclear decommissioning trust fund securities (153 ) —
—
—
(153 )
Proceeds from sales of nuclear decommissioning trust fund securities 117
—
—
—
117
Proceeds from sale of assets, net of cash disposed of 11
3
—
—
14
Investments in unconsolidated affiliates —
(12 ) —
—
(12 )
Other 18
—
—
—
18
Net Cash (Used)/Provided by Investing Activities (63 ) (296 ) 147
(20 ) (232 )
Cash Flows from Financing Activities

Dividends from NRG Yield, Inc. —
(22 ) —
22
—
Payments from/(for) intercompany loans 65
(428 ) 395
(32 ) —
Acquisition of Drop Down Assets, net of cash acquired —
—
131
(131 ) —
Intercompany dividends —
(129 ) —
129
—
Payment of dividends to common and preferred stockholders —
—
(9 ) —
(9 )
Net receipts from settlement of acquired derivatives that include financing elements —
1
—
—
1
Proceeds from issuance of long-term debt —
166
26
—
192
Payments for short and long-term debt —
(146 ) (31 ) —
(177 )
Payment for credit support in long-term deposits —
(130 ) —
—
(130 )
Proceeds from draw on revolving credit facility for long-term deposits —
125
—
—
125
Increase in long-term deposits —
(125 ) —
—
(125 )
Contributions to, net of distributions from, noncontrolling interest in subsidiaries —
(5 ) —
—
(5 )
Payment of debt issuance costs —
(11 ) (4 ) —
(15 )
Other - contingent consideration —
(10 ) —
—
(10 )
Net Cash Provided/(Used) by Financing Activities 65
(714 ) 508
(12 ) (153 )
Effect of exchange rate changes on cash and cash equivalents —
(7 ) —
—
(7 )
Net Decrease in Cash and Cash Equivalents —
(393 ) (67 ) —
(460 )
Cash and Cash Equivalents at Beginning of Period —
1,650
323
—
1,973
Cash and Cash Equivalents at End of Period $ —

$ 1,257

$ 256

$ —
$ 1,513


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~For the three months ended March 31, 2016~~

~~(Unaudited)~~

Guarantor Subsidiaries Non-Guarantor Subsidiaries
NRG Energy, Inc.
(Note Issuer)

Eliminations^(a)
Consolidated
(In millions)
Operating Revenues
Total operating revenues $ 1,956
$ 1,299
$ —
$ (26 ) $ 3,229
Operating Costs and Expenses
Cost of operations 1,455
759
10
(30 ) 2,194
Depreciation and amortization 117
190
6
—
313
Selling, general and administrative 93
99
60
—
252
Development activity expenses —
19
7
—
26
Total operating costs and expenses 1,665
1,067
83
(30 ) 2,785
Gain on sale of assets —
32
—
—
32
Operating Income/(Loss) 291
264
(83 ) 4
476
Other Income/(Expense)

Equity in (losses)/earnings of consolidated subsidiaries (24 ) 4
213
(193 ) —
Equity in losses of unconsolidated affiliates —
(8 ) —
1
(7 )
Impairment loss on investment —
(140 ) (6 ) —
(146 )
Other income/(expense), net —
20
(2 ) —
18
Gain on debt extinguishment —
—
11
—
11
Interest expense (5 ) (150 ) (129 ) —
(284 )
Total other (expense)/income (29 ) (274 ) 87
(192 ) (408 )
Income/(Loss) Before Income Taxes 262
(10 ) 4
(188 ) 68
Income tax expense/(benefit) 100
(8 ) (83 ) 12
21
Net Income/(Loss) 162
(2 ) 87
(200 ) 47
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest —
(33 ) 5
(7 ) (35 )
Net Income Attributable to NRG Energy, Inc. $ 162
$ 31
$ 82
$ (193 ) $ 82


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME~~

~~For the three months ended March 31, 2016~~

~~(Unaudited)~~

Guarantor Subsidiaries Non-Guarantor Subsidiaries
NRG Energy, Inc.
(Note Issuer)

Eliminations^(a)
Consolidated
(In millions)
Net Income/(Loss) $ 162
$ (2 ) $ 87
$ (200 ) $ 47
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net —
(50 ) 24
(6 ) (32 )
Foreign currency translation adjustments, net 4
4
6
(8 ) 6
Available-for-sale securities, net —
—
3
—
3
Defined benefit plans, net 1
—
—
—
1
Other comprehensive income/(loss) 5
(46 ) 33
(14 ) (22 )
Comprehensive Income/Loss 167
(48 ) 120
(214 ) 25
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest —
(50 ) 5
(7 ) (52 )
Comprehensive Income Attributable to NRG Energy, Inc. 167
2
115
(207 ) 77
Dividends for preferred shares —
—
5
—
5
Comprehensive Income Available for Common Stockholders $ 167
$ 2
$ 110
$ (207 ) $ 72


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

CONDENSED CONSOLIDATING BALANCE SHEETS

~~December 31, 2016~~September 30, 2017

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations ^(a)			Consolidated		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)														(In millions)
Current Assets
Cash and cash equivalents	$	—		$	1,650		$	323		$	—		$	1,973	$	(20	)	$	350		$	893		$	—		$	1,223
Funds deposited by counterparties	2			—			—			—			2		29			2			—			—			31
Restricted cash	11			435			—			—			446		14			523			—			—			537
Accounts receivable - trade, net	734			429			3			—			1,166		876			395			3			—			1,274
Accounts receivable - affiliate	309			(241		)	200			(262		)	6		222			191			(22		)	(337		)	54
Inventory	482			629			—			—			1,111		406			224			—			—			630
Derivative instruments	962			305			—			(205		)	1,062		438			106			5			(74		)	475
Cash collateral paid in support of energy risk management activities	37			166			—			—			203
Current assets held-for-sale	—			9			—			—			9
Cash collateral posted in support of energy risk management activities															190			13			—			—			203
Prepayments and other current assets	76			279			62			—			417		108			147			45			—			300
Current assets - held for sale															—			33			—			—			33
Total current assets	2,613			3,661			588			(467		)	6,395		2,263			1,984			924			(411		)	4,760
Net Property, Plant and Equipment	4,216			13,472			251			(27		)	17,912
Net property, plant and equipment															3,980			11,142			236			(26		)	15,332
Other Assets
Investment in subsidiaries	837			1,973			10,128			(12,938		)	—		1,098			1,004			9,409			(11,511		)	—
Equity investments in affiliates	(14		)	1,129			5			—			1,120		—			1,135			3			—			1,138
Notes receivable, less current portion	—			17			(76		)	76			17		—			5			—			—			5
Goodwill	359			303			—			—			662		359			303			—			—			662
Intangible assets, net	592			1,447			—			(3		)	2,036		520			1,321			—			(3		)	1,838
Nuclear decommissioning trust fund	610			—			—			—			610		670			—			—			—			670
Derivative instruments	143			60			36			(50		)	189		187			38			27			(46		)	206
Deferred income taxes	3			868			(646		)	—			225
Non-current assets held for sale	—			10			—			—			10
Deferred income tax															(5		)	(148		)	358			—			205
Non-current assets held-for-sale															—			10			—			—			10
Other non-current assets	67			784			328			—			1,179		63			520			61			—			644
Total other assets	2,597			6,591			9,775			(12,915		)	6,048		2,892			4,188			9,858			(11,560		)	5,378
Total Assets	$	9,426		$	23,724		$	10,614		$	(13,409	)	$	30,355	$	9,135		$	17,314		$	11,018		$	(11,997	)	$	25,470
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	1,202		$	(58	)	$	76		$	1,220	$	—		$	623		$	624		$	—		$	1,247
Accounts payable	499			362			34			—			895		599			285			31			—			915
Accounts payable — affiliate	655			1,834			(2,227		)	(262		)	—		528			(340		)	146			(338		)	(4		)
Derivative instruments	947			342			—			(205		)	1,084		418			178			—			(74		)	522
Cash collateral received in support of energy risk management activities	2			—			—			—			2		29			2			—			—			31
Current liabilities held-for-sale	—			—			—			—			—
Accrued expenses and other current liabilities	317			400			464			—			1,181		301			57			472			—			830
Accrued expenses and other current liabilities-affiliate															—			164			—			—			164
Total current liabilities	2,420			4,140			(1,787		)	(391		)	4,382		1,875			969			1,273			(412		)	3,705
Other Liabilities
Long-term debt and capital leases	244			10,302			7,460			—			18,006		244			8,644			6,770			—			15,658
Nuclear decommissioning reserve	287			—			—			—			287		265			—			—			—			265
Nuclear decommissioning trust liability	339			—			—			—			339		397			—			—			—			397
Deferred income taxes	186			(1,094		)	928			—			20		428			—			(407		)	—			21
Derivative instruments	157			187			—			(50		)	294		194			159			—			(46		)	307
Out-of-market contracts, net	80			960			—			—			1,040		69			144			—			—			213
Non-current liabilities held-for-sale	—			12			—			—			12		—			13			—			—			13
Other non-current liabilities	397			762			324			—			1,483		377			315			424			—			1,116
Total non-current liabilities	1,690			11,129			8,712			(50		)	21,481		1,974			9,275			6,787			(46		)	17,990
Total Liabilities	4,110			15,269			6,925			(441		)	25,863
Total liabilities															3,849			10,244			8,060			(458		)	21,695
Redeemable noncontrolling interest in subsidiaries	—			46			—			—			46		—			85			—			—			85
Stockholders’ Equity	5,316			8,409			3,689			(12,968		)	4,446		5,286			6,985			2,958			(11,539		)	3,690
Total Liabilities and Stockholders’ Equity	$	9,426		$	23,724		$	10,614		$	(13,409	)	$	30,355	$	9,135		$	17,314		$	11,018		$	(11,997	)	$	25,470


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended September 30, 2017 (Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income/(loss)	$	427		$	(785	)	$	(564	)	$	240		$	(682	)
Loss from discontinued operations	—			(802		)	—			—			(802		)
Net income/(loss) from continuing operations	427			17			(564		)	240			120
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			60			—			(7		)	53
Equity in losses/(earnings) of unconsolidated affiliates	—			(101		)	3			69			(29		)
Depreciation and amortization	307			458			24			—			789
Provision for bad debts	40			2			15			—			57
Amortization of nuclear fuel	37			—			—			—			37
Amortization of financing costs and debt discount/premiums	—			31			13			—			44
Adjustment for debt extinguishment	—			3			—			—			3
Amortization of intangibles and out-of-market contracts	20			59			—			—			79
Amortization of unearned equity compensation	—			—			27			—			27
Impairment losses	42			35			—			—			77
Changes in deferred income taxes and liability for uncertain tax benefits	244			28			(246		)	—			26
Changes in nuclear decommissioning trust liability	20			—			—			—			20
Changes in derivative instruments	(11		)	32			12			(8		)	25
Changes in collateral deposits supporting energy risk management activities	(126		)	23			—			—			(103		)
Proceeds from sale of emission allowances	21			—			—			—			21
Gain on sale of assets	(22		)	—			—			—			(22		)
Cash (used)/provided by changes in other working capital	(958		)	(523		)	1,395			(294		)	(380		)
Cash provided by continuing operations	41			124			679			—			844
Cash used by discontinued operations	—			(38		)	—			—			(38		)
Net Cash Provided by Operating Activities	41			86			679			—			806
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			69			(69		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(176		)	—			176			—
Intercompany dividends	—			—			129			(129		)	—
Acquisition of business, net of cash acquired	—			(36		)	—			—			(36		)
Capital expenditures	(135		)	(606		)	(19		)	—			(760		)
Decrease in notes receivable	—			11			—			—			11
Purchases of emission allowances	(47		)	—			—			—			(47		)
Proceeds from sale of emission allowances	105			—			—			—			105
Investments in nuclear decommissioning trust fund securities	(402		)	—			—			—			(402		)
Proceeds from sales of nuclear decommissioning trust fund securities	382			—			—			—			382
Proceeds from renewable energy grants and state rebates	8			—			—			—			8
Proceeds from sale of assets, net of cash disposed of	36			—			—			—			36
Investments in unconsolidated affiliates	—			(31		)	—			—			(31		)
Other	22			—			—			—			22
Cash (used)/provided by continuing operations	(31		)	(838		)	179			(22		)	(712		)
Cash used by discontinued operations	—			(53		)	—			—			(53		)
Net Cash (Used)/Provided by Investing Activities	(31		)	(891		)	179			(22		)	(765		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(69		)	—			69			—
Payments from/(for) intercompany loans	9			417			(426		)	—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			176			(176		)	—
Intercompany dividends	—			(129		)	—			129			—
Payment of dividends to common and preferred stockholders	—			—			(28		)	—			(28		)
Net receipts from settlement of acquired derivatives that include financing elements	—			2			—			—			2
Proceeds from issuance of long-term debt	—			920			214			—			1,134
Payments for short and long-term debt	—			(493		)	(219		)	—			(712		)
Receivable from affiliate	—			(125		)	—			—			(125		)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries	—			65			—			—			65
Payment of debt issuance costs	—			(38		)	(5		)	—			(43		)
Other - contingent consideration	—			(10		)	—			—			(10		)
Cash provided/(used) by continuing operations	9			540			(288		)	22			283
Cash used by discontinued operations	—			(224		)	—			—			(224		)
Net Cash Provided/(Used) by Financing Activities	9			316			(288		)	22			59
Change in cash from discontinued operations	—			(315		)	—			—			(315		)
Effect of exchange rate changes on cash and cash equivalents	—			(10		)	—			—			(10		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	19			(184		)	570			—			405
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	4			1,059			323			—			1,386
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	23		$	875		$	893		$	—		$	1,791

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended ~~March 31,~~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/(loss) $ 162
$ (2 ) $ 87
$ (200 ) $ 47
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates —
22
—
(12 ) 10
Equity in losses of unconsolidated affiliates —
8
—
(1 ) 7
Depreciation and amortization 117
190
6
—
313
Provision for bad debts 8
2
—
—
10
Amortization of nuclear fuel 13
—
—
—
13
Amortization of financing costs and debt discount/premiums —
7
(6 ) —
1
Adjustment for debt extinguishment —
—
(11 ) —
(11 )
Amortization of intangibles and out-of-market contracts 11
15
—
—
26
Amortization of unearned equity compensation —
—
8
—
8
Impairment losses —
140
6
—
146
Changes in deferred income taxes and liability for uncertain tax benefits (613 ) (1,696 ) 2,284
—
(25 )
Changes in nuclear decommissioning trust liability 9
—
—
—
9
Changes in derivative instruments (28 ) (22 ) —
—
(50 )
Changes in collateral deposits supporting energy risk management activities 150
6
—
—
156
Proceeds from sale of emission allowances 47
—
—
—
47
Gain on sale of assets —
(32 ) —
—
(32 )
Cash provided/(used) by changes in other working capital 338
1,728
(2,400 ) 213
(121 )
Net Cash Provided/(Used) by Operating Activities 214
366

(26 )
—
554
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc. —
(19 ) —
19
—
Acquisition of businesses, net of cash acquired —
(6 ) —
—
(6 )
Capital expenditures (44 ) (219 ) (16 ) —
(279 )
Increase in restricted cash, net (2 ) (10 ) —
—
(12 )
Decrease in restricted cash - U.S. DOE funded projects —
39
—
—
39
Decrease in notes receivable —
1
—
—
1
Purchases of emission allowances (12 ) —
—
—
(12 )
Proceeds from sale of emission allowances 7
—
—
—
7
Investments in nuclear decommissioning trust fund securities (200 ) —
—
—
(200 )
Proceeds from sales of nuclear decommissioning trust fund securities 191
—
—
—
191
Proceeds from renewable energy grants and state rebates —
8
—
—
8
Proceeds from sale of assets, net of cash disposed of —
120
—
—
120
Investments in unconsolidated affiliates —
(4 ) —
—
(4 )
Other —
4
—
—
4
Net Cash Used by Investing Activities (60 ) (86 ) (16 )
19
(143 )
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc. —
—
19
(19 ) —
Payments (for)/from intercompany loans (151 ) (11 ) 162

—
Payment of dividends to common and preferred stockholders —
—
(48 ) —
(48 )
Net receipts for settlement of acquired derivatives that include financing elements —
39
—
—
39
Proceeds from issuance of long-term debt —
61
—
—
61
Payments for short and long-term debt —
(121 ) (195 ) —
(316 )
Distributions from, net of contributions to, noncontrolling interest in subsidiaries —
10
—
—
10
Other (3 ) (7 ) —
—
(10 )
Net Cash Used by Financing Activities (154 ) (29 ) (62 ) (19 ) (264 )
Effect of exchange rate changes on cash and cash equivalents —
(6 ) —
—
(6 )
Net Increase/(Decrease) in Cash and Cash Equivalents —
245
(104 ) —
141
Cash and Cash Equivalents at Beginning of Period —
825
693
—
1,518
Cash and Cash Equivalents at End of Period $ —
$ 1,070
$ 589
$ —
$ 1,659



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,424		$	1,090		$	—		$	(93	)	$	3,421
Operating Costs and Expenses
Cost of operations	1,719			804			10			(93		)	2,440
Depreciation and amortization	147			144			7			—			298
Impairment losses	8			1			—			—			9
Selling, general and administrative	115			50			112			—			277
Development activity expenses	—			10			11			—			21
Total operating costs and expenses	1,989			1,009			140			(93		)	3,045
Other income - affiliate	—			—			48			—			48
Gain on sale of assets	—			—			4			—			4
Operating Income/(Loss)	435			81			(88		)	—			428
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(114		)	(10		)	562			(438		)	—
Equity in earnings/(losses) of unconsolidated affiliates	2			75			(12		)	(49		)	16
Loss on investment	—			(8		)	—			—			(8		)
Other income/(loss), net	1			6			��			—			7
Loss on debt extinguishment	—			—			(50		)	—			(50		)
Interest expense	(4		)	(104		)	(129		)	—			(237		)
Total other expense	(115		)	(41		)	371			(487		)	(272		)
Income from Continuing Operations Before Income Taxes	320			40			283			(487		)	156
Income tax expense/(benefit)	134			45			(151		)	—			28
Income from Continuing Operations	186			(5		)	434			(487		)	128
Income from Discontinued Operations, net of income tax	—			263			2			—			265
Net Income	186			258			436			(487		)	393
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—			6			34			(49		)	(9		)
Net Income Attributable to NRG Energy, Inc.	$	186		$	252		$	402		$	(438	)	$	402


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

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		$	2,400		$	—		$	(151	)	$	8,328
Operating Costs and Expenses
Cost of operations	4,278			1,558			29			(154		)	5,711
Depreciation and amortization	372			435			19			—			826
Impairment losses	8			57			—			—			65
Selling, general and administrative	306			144			351			—			801
Development activity expenses	—			42			23			—			65
Total operating costs and expenses	4,964			2,236			422			(154		)	7,468
Other income - affiliate	—			—			144			—			144
Loss on sale of assets	—			—			(79		)	—			(79		)
Operating Income/(Loss)	1,115			164			(357		)	3			925
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(195		)	(80		)	904			(629		)	—
Equity in earnings/(losses) of unconsolidated affiliates	5			114			(2		)	(104		)	13
Impairment loss on investment	—			(147		)	—			—			(147		)
Other income, net	3			25			2			(1		)	29
Loss on debt extinguishment	—			(4		)	(115		)	—			(119		)
Interest expense	(11		)	(312		)	(395		)				(718		)
Total other (expense)/income	(198		)	(404		)	394			(734		)	(942		)
Income/(Loss) Before Income Taxes	917			(240		)	37			(731		)	(17		)
Income tax expense/(benefit)	362			(49		)	(238		)	—			75
Income/(Loss) from Continuing Operations	555			(191		)	275			(731		)	(92		)
Income from Discontinued Operations, net of income tax	—			248			8			—			256
Net Income	555			57			283			(731		)	164
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(17		)	70			(102		)	(49		)
Net Income Attributable to NRG Energy, Inc.	$	555		$	74		$	213		$	(629	)	$	213


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

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	$	186	$	258	$	436		$	(487	)	$	393
Other Comprehensive Income/(Loss), net of tax
Unrealized income on derivatives, net	—		40		26			(39		)	27
Foreign currency translation adjustments, net	2		2		4			(5		)	3
Defined benefit plans, net	54		—		(43		)	20			31
Other comprehensive loss	56		42		(13		)	(24		)	61
Comprehensive Income	242		300		423			(511		)	454
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—		13		34			(49		)	(2		)
Comprehensive Income Attributable to NRG Energy, Inc.	$	242	$	287	$	389		$	(462	)	$	456


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

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	$	555	$	57		$	283		$	(731	)	$	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		—			(43		)	20			32
Other comprehensive income/(loss)	59		(11		)	10			(27		)	31
Comprehensive Income	614		46			293			(758		)	195
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(38		)	70			(102		)	(70		)
Comprehensive Income Attributable to NRG Energy, Inc.	614		84			223			(656		)	265
Dividends for preferred shares	—		—			5			—			5
Gain on redemption of preferred shares	—		—			(78		)	—			(78		)
Comprehensive Income Available for Common Stockholders	$	614	$	84		$	296		$	(656	)	$	338


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2016



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations ^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	(9	)	$	624		$	323		$	—		$	938
Funds deposited by counterparties	2			—			—			—			2
Restricted cash	11			435			—			—			446
Accounts receivable - trade, net	734			321			3			—			1,058
Accounts receivable - affiliate	307			(254		)	200			(139		)	114
Inventory	482			239			—			—			721
Derivative instruments	962			196			1			(92		)	1,067
Cash collateral posted in support of energy risk management activities	116			34			—			—			150
Current assets held-for-sale	—			9			—			—			9
Prepayments and other current assets	76			152			62			—			290
Current assets - discontinued operations	—			1,919			—			—			1,919
Total current assets	2,681			3,675			589			(231		)	6,714
Net Property, Plant and Equipment	4,219			10,926			251			(27		)	15,369
Other Assets
Investment in subsidiaries	1,090			1,054			10,128			(12,272		)	—
Equity investments in affiliates	(13		)	1,128			5			—			1,120
Notes receivable, less current portion	—			16			—			—			16
Goodwill	359			303			—			—			662
Intangible assets, net	592			1,384			—			(3		)	1,973
Nuclear decommissioning trust fund	610			—			—			—			610
Derivative instruments	144			44			36			(43		)	181
Deferred income taxes	3			—			222			—			225
Non-current assets held for sale	—			10			—			—			10
Other non-current assets	67			446			328			—			841
Non-current assets - discontinued operations	—			2,961			—			—			2,961
Total other assets	2,852			7,346			10,719			(12,318		)	8,599
Total Assets	$	9,752		$	21,947		$	11,559		$	(12,576	)	$	30,682
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	498		$	18		$	—		$	516
Accounts payable	501			247			34			—			782
Accounts payable — affiliate	744			(452		)	(122		)	(139		)	31
Derivative instruments	947			237			—			(92		)	1,092
Cash collateral received in support of energy risk management activities	81			—			—			—			81
Accrued expenses and other current liabilities	316			209			465			—			990
Current liabilities - discontinued operations	—			1,210			—			—			1,210
Total current liabilities	2,589			1,949			395			(231		)	4,702
Other Liabilities
Long-term debt and capital leases	244			8,252			7,461			—			15,957
Nuclear decommissioning reserve	287			—			—			—			287
Nuclear decommissioning trust liability	339			—			—			—			339
Deferred income taxes	186			125			(291		)	—			20
Derivative instruments	157			170			—			(43		)	284
Out-of-market contracts, net	80			150			—			—			230
Non-current liabilities held-for-sale	—			11			—			—			11
Other non-current liabilities	396			456			324			—			1,176
Non-current liabilities - discontinued operations	—			3,184			—			—			3,184
Total non-current liabilities	1,689			12,348			7,494			(43		)	21,488
Total Liabilities	4,278			14,297			7,889			(274		)	26,190
Redeemable noncontrolling interest in subsidiaries	—			46			—			—			46
Stockholders’ Equity	5,474			7,604			3,670			(12,302		)	4,446
Total Liabilities and Stockholders’ Equity	$	9,752		$	21,947		$	11,559		$	(12,576	)	$	30,682


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

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	$	555		$	57		$	283		$	(731	)	$	164
Less: Income from discontinued operations	—			248			8			—			256
Net income/(loss) from continuing operations	555			(191		)	275			(731		)	(92		)
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			435			19			—			826
Provision for bad debts	31			5			—			—			36
Amortization of nuclear fuel	39			—			—			—			39
Amortization of financing costs and debt discount/premiums	—			25			17			—			42
Adjustment for debt extinguishment	—			102			17			—			119
Amortization of intangibles and out-of-market contracts	32			99			—			—			131
Amortization of unearned equity compensation	—			—			23			—			23
Impairment losses	8			203			—			—			211
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		)	206			(3		)	—			30
Changes in collateral posted supporting energy risk management activities	268			(7		)	—			—			261
Proceeds from sale of emission allowances	11			—			—			—			11
Loss on sale of assets	—			—			70			—			70
Cash (used)/provided by changes in other working capital	(827		)	168			(200		)	729			(130		)
Net cash provided by continuing operations	201			1,000			473			—			1,674
Cash provided by discontinued operations	—			67			—			—			67
Net Cash Provided by Operating Activities	201			1,067			473			—			1,741
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		)	(474		)	(40		)	—			(659		)
Increase 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	—			67			17			—			84
Investments in unconsolidated affiliates	2			(25		)	—			—			(23		)
Other	27			(4		)	8			—			31
Net cash (used)/provided by continuing operations	(125		)	(518		)	56			6			(581		)
Cash provided by discontinued operations	—			326			—			—			326
Net Cash (Used)/Provided by Investing Activities	(125		)	(192		)	56			6			(255		)
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 for settlement of acquired derivatives that include financing elements	—			6			—			—			6
Proceeds from issuance of long-term debt	—			1,097			4,140			—			5,237
Payments for short and long-term debt	(2		)	(811		)	(4,540		)	—			(5,353		)
Payments for debt extinguishment costs	—			(98		)	—			—			(98		)
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	(3		)	(7		)	—			—			(10		)
Net cash used by continuing operations	(59		)	(110		)	(531		)	(6		)	(706		)
Cash provided by discontinued operations	—			119			—			—			119
Net Cash (Used)/Provided by Financing Activities	(59		)	9			(531		)	(6		)	(587		)
Change in cash from discontinued operations	—			512			—			—			512
Effect of exchange rate changes on cash and cash equivalents	—			(6		)	—			—			(6		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties	17			366			(2		)	—			381
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period	—			629			693			—			1,322
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period	$	17		$	995		$	691		$	—		$	1,703


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

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 ~~March 31,~~September 30, 2017 and 2016. Also refer to NRG's 2016 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.

Executive Summary

Introduction and Overview

The following table summarizes NRG's global generation portfolio as of ~~March 31,~~September 30, 2017, by operating segment:


	Global Generation Portfolio^(a)											Global Generation Portfolio^(a)(b)
	(In MW)											(In MW)
	Generation											Generation
Generation Type	Gulf Coast	East	West	Other	Renewables ^(b)		NRG Yield ^(c)		Other ^(d)	Total Global		Gulf Coast	East/West ^(c)	Renewables^(d)		NRG Yield^(e)		Other^(f)	Total Global
Natural gas^(e)(g)	8,613	8,444	4,899	144	—		1,878		22	24,000		7,464	4,939	—		1,878		—	14,281
Coal	5,114	7,465	—	605	—		—		—	13,184		5,114	3,869	—		—		—	8,983
Oil	—	5,477	—	—	—		190		—	5,667		—	3,642	—		190		—	3,832
Nuclear	1,136	—	—	—	—		—		—	1,136		1,136	—	—		—		—	1,136
Wind	—	—	—	—	961		2,005		—	2,966		—	—	743		2,206		—	2,949
Utility Scale Solar	—	—	—	—	722		921		—	1,643		—	—	742		921		—	1,663
Distributed Solar	—	—	—	—	121		14		114	249		—	—	175		14		114	303
Total generation capacity^(f)(g)	14,863	21,386	4,899	749	1,804		5,008		136	48,845		13,714	12,450	1,660		5,209		114	33,147
Capacity attributable to noncontrolling interest^(f)(h)	—	—	—	—	(684	)	(2,252	)	—	(2,936	)	—	—	(684	)	(2,342	)	—	(3,026	)
Total net generation capacity	14,863	21,386	4,899	749	1,120		2,756		136	45,909		13,714	12,450	976		2,867		114	30,121

(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)	GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG on June 14, 2017.

~~(b)~~(c) Includes International and BETM.

(d) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2.

~~(c)~~(e) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.

~~(d)~~(f) 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)~~(g) Natural gas generation does not include ~~1,029 MW related to Pittsburg which GenOn Americas Generation deactivated on January 1, 2017,~~ 51 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and retired on January 1, 2017, and 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017.

(f) NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,002 MWs.


(h)	NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,203 MWs.

~~Strategy~~GenOn

~~NRG's strategy is to maximize stockholder value through~~On June 14, 2017, GenOn, GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, all of which are subsidiaries of NRG, filed voluntary petitions for relief under Chapter 11 of the ~~safe production and sale of reliable and affordable power to its customers~~U.S. Bankruptcy Code 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~~United States Bankruptcy Court for the ~~benefit~~Southern District of Texas, Houston Division. As a result 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~~bankruptcy filings and ~~mitigated exposure both to environmental risk~~beginning on June 14, 2017, GenOn and ~~cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for~~ its ~~employees, customers and partners continues unabated.~~subsidiaries, representing approximately 15,000 MW, were deconsolidated from NRG’s consolidated financial statements.

~~To effectuate~~

Transformation Plan

On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the ~~Company’s strategy, NRG is focused on: (i)~~following targets:

Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in ~~operating performance~~maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales.

Portfolio optimization — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its ~~existing assets including repowering~~interest in NRG Yield, Inc. and its ~~power generation assets at premium sites~~renewables platform.

Capital structure 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 alternative power generation technologies in its wholesale business, like wind and solar, and deploying innovative energy solutions for consumers within its retail businesses; and (iv) engaging in a proactiveallocation enhancements — A prioritized capital allocation ~~plan focused on~~strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales, the Company expects $4.8-$6.3 billion in excess cash to be available for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.

The Company expects to fully implement the ~~regular return~~Transformation Plan by the end of 2020 with significant completion by the end of 2018. The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and ~~on stockholder capital within the dictates of prudent balance sheet management, including pursuing selective acquisitions, joint ventures, divestitures and investments.~~(ii) approximately $290 million, one-time costs to achieve.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2016 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note ~~15,~~16, 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 NRG 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 NRG's ownership interest in STP.

East Region

PJM

~~PJM Seasonal Capacity Proceeding~~Minimum Offer Price Rule Exemption Appeal —On ~~November 17, 2016, PJM proposed~~July 7, 2017, the D.C. Circuit vacated a FERC order from 2013 related to ~~allow winter-~~an exemption to the Minimum Offer Price Rule, or MOPR, and ~~summer-peaking capacity resources~~remanded the issue back to “aggregate” their seasonal capacity into an annual capacity product eligible to participate as Capacity Performance resources. NRG filed comments specifically supporting PJM’s proposal to modify the aggregation rules to allow seasonal capacity resources to aggregate across LDAs and to allow aggregations through RPM auctions.FERC. On ~~January~~October 23, 2017, PJM ~~amended~~re-filed its initial 2012 MOPR. FERC's ruling on PJM's renewed proposal ~~to address questions from FERC. On March 21, 2017, FERC issued a decision accepting PJM's seasonal capacity aggregation filing. The outcome of this proceeding~~ could ~~have a material impact on future~~affect how generators participate in the PJM ~~capacity prices.~~Base Residual Auction.

~~Complaints Regarding Pseudo-Ties for Capacity~~2020/2021 PJM Auction Results — On ~~April 6,~~May 23, 2017, ~~Potomac Economics,~~PJM announced the ~~market monitor~~results of its 2020/2021 base residual auction. NRG, excluding GenOn, cleared approximately 3,992 MW of Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, from the base residual auction for ~~MISO and NYISO, filed~~the 2020/2021 delivery year are approximately $268 million. For results of the 2019/2020 PJM base residual auction, refer to Item 1 - Business of the 2016 Form 10-K.

The table below provides a ~~complaint against PJM regarding the participation~~detailed description of ~~external~~NRG’s 2020/2021 base residual auction result:



	Capacity Performance Product
Zone	Cleared Capacity (MW)^(a)	Price ($/MW-day)
COMED	3,315	$188.12
EMAAC	519	$187.87
MAAC	158	$86.04
Total	3,992

(a) Includes imports. Does not include capacity resources in PJM’s auction. Currently, external resources must enter into a pseudo-tie agreement in order to sell capacity into PJM. The complaint alleges that the pseudo-tie requirements is causing market inefficiencies in PJM, New York and MISO and suggests a new protocol for incorporating external resources into PJM’s markets. In addition, other market participants have filed separate complaints at FERC against MISO or PJM, respectively, for issues resulting from pseudo-tied generators. The complainants argue that the generation owners with pseudo-ties from MISO to PJM are receiving double-charges for congestion. The outcome could impact the PJM, NYISO and MISO capacity markets.sold by NRG Curtailment Specialists.

New England

2020/2021 ISO-NE Auction Results — On February 6, 2017, ISO-NE announced the results of its 2020/2021 forward capacity auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual capacity revenues of $167.9 million. The 333 MWs at Canal Unit 3, which previously cleared the tenth forward capacity auction with a seven year price lock at a price of ~~$7.17~~$7.03 KW per month for the 2020/2021 deliverability year, are excluded from these results.

Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. The ~~parties are currently in~~ settlement ~~negotiations~~is pending at FERC. The outcome of this matter will determine the amount of refunds that the NRG fleet may receive as a result of negotiating the PER strike price methodology.

New York

New York Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order, in docket 12-M-0476 et al. Among other things, the Reset Order ~~instituted~~placed a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail ~~customers over a very short period of time~~customers. Various parties have challenged the NYPSC’s ability to ~~retain those customers. Retail~~regulate rates charged by competitive suppliers ~~who cannot meet these conditions will be required to return their customers to energy supply service provided by the local utility. On July 25, 2016, the~~in New York ~~Supreme Court vacated part of~~state court. In conjunction with the ~~Reset Order on procedural grounds and remanded~~court challenges, the ~~matter~~NYPSC is scheduled to the NYSPSC for further consideration. Additionally, the Court affirmed the NYSPSC’s authority to regulate Energy Service Companies prices. The matter is now on appeal before the Supreme Court of New York, Appellate Division. On December 2, 2016 in the same docket, the NYSPSC issued notice ofcommence an evidentiary proceeding ~~and collaborative process to determine~~on the ~~future structure~~functioning of the competitive retail energy market in New York. On January 26, 2017, the Administrative Law Judge assigned to the proceeding commenced the evidentiary proceeding, including discovery, and set a schedule for pre-filed testimony, with the evidentiary hearing set to commence in the summer ofmarkets on November 29, 2017. ~~The collaborative process has not yet been commenced or scheduled.~~ The outcome of this evidentiary and collaborative process, combined with the outcome of the appeal of the ~~Reset Order,~~Appellate Division order, could affect the viability of the New York retail energy market.

~~Gulf Coast Region~~

~~ERCOT~~General

~~Greens Bayou Unit 5 RMR Status~~State Out-Of-Market Subsidy Proposals — ~~On March 29, 2016,~~Certain states including Connecticut, New Jersey, Ohio and Pennsylvania have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units. NRG ~~filed notice with ERCOT~~has opposed those efforts to provide out of ~~its intent~~market subsidies, and intends to ~~mothball Greens Bayou Unit 5. On May 27, 2016, ERCOT made a final determination that~~continue opposing them in 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. ERCOT provided formal notice to NRG on February 27, 2017 that the RMR agreement will terminate on May 29, 2017. On March 31, 2017, NRG notified ERCOT that Greens Bayou Unit 5 will be returned to mothball status after the RMR agreement terminates.future.

West Region

CAISO

Puente Power Project — On May 26, 2016, the CPUC approved the resource adequacy purchase agreement, or RAPA, between SCE and NRG for the construction of the 262 MW natural gas peaking Puente Power Project. On July 1, 2016, four different parties sought rehearing of the CPUC's approval of the RAPA. On December 1, 2016, the CPUC affirmed approval of the RAPA in a rehearing decision. On January 4, 2017, a petition for request for review was filed in the California Court of Appeal seeking to reverse the CPUC's approval of the RAPA. Briefing in connection with the petition for request for review was completed on March 20, 2017 and the parties are now awaiting the court’s decision on whether to review the case. In addition, on March 10,October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued ~~an order requesting additional information after hearings had already concluded in February 2017. The CEC’s request will result in~~ a ~~several month delay in the processing of Puente’s permit; however, this permitting delay has not changed the project's estimated commercial operation date~~statement on behalf of the ~~second quarter~~committee of ~~2020.~~two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months. A hearing on the motion was held on October 31, 2017, after which the CEC took the matter under submission subject to a written decision to be issued at an unspecified later date. If the CEC Commissioners accept the recommendation, and formally deny a permit for the Puente Power Project, then the project will not move forward.

Nuclear Operations

Decommissioning Trusts — Upon expiration of the operating licenses for the two generating units at STP, recently extended until 2047 and 2048, respectively, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.

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 maintained 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. Requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species have been put in place in recent years. However, under the ~~new~~current U.S. presidential administration, some of these rules are being reconsidered and reviewed. 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 have been recently promulgated by the EPA but are being reconsidered, including ESPS/NSPS for GHGs, NAAQS revisions and implementation, and effluent guidelines. NRG is evaluating the potential outcomes and any resulting impacts of recently promulgated regulations that the EPA is now reconsidering and cannot fully predict such impacts until administrative reconsiderations and legal challenges are resolved. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the ~~new~~current U.S. presidential administration. The Company’s environmental matters are described in the Company’s 2016 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note ~~16,~~17, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.

National

Air

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO₂, ozone, and PM_2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have historically become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent NAAQS could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economical. Significant changes to air regulatory programs affecting the Company are described below.

Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. Challenges to this rule have been stayed at the request of the EPA so that it can evaluate the rule. If the rule is not altered by the EPA and survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NO_x (an ozone precursor), which could affect some of the Company's units.

Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The D.C. Circuit ~~sitting all of the active judges,~~ heard oral argument on the legal challenges to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in ~~abeyance for 60 days. Due~~abeyance. On October 16, 2017, the EPA proposed a rule to ~~a recent Executive Order and various steps taken by~~repeal the ~~new U.S. presidential administration,~~CPP. Accordingly, the Company believes the CPP is not likely to survive.

Byproducts, Wastes, Hazardous Materials and Contamination

Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.

On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal has been reviewed for adequacy and, with advice of counsel, was accepted. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools. Since STPNOC's SNF storage pools do not have sufficient storage capacity for the life of the units, STPNOC is proceeding to construct dry cask storage capability on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. STP's warehouse capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.

Regional Environmental Developments

~~East Region~~

~~Burton Island Old Ash Landfill~~ — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program, or the VCP. On February 4, 2008, DNREC issued findings that no further action was required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and on track for completion in the second quarter of 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.

Gulf Coast Region

Texas Regional Haze — ~~In January 2016,~~On October 17, 2017, the EPA promulgated a final rule ~~that requires 15 coal-fired units (at eight plants in Texas) to reduce their~~creating a Texas-only SO₂ ~~rates at various times over the next five years if the rule survives legal challenges. This Regional Haze rule was promulgated under the portion~~cap-and-trade program to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the ~~CAA that seeks to improve visibility at national parks. Eight of these 15~~Company's units ~~already have scrubbers and seven do not. NRG owns two of the~~in Texas will be 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. On December 2, 2016, the EPA filed a motion in the Fifth Circuit for partial voluntary remand and partial lifting of the stay, but did not request vacatur of the final rule. On March 22, 2017, the Fifth Circuit remanded the rule to the EPA so that it could reconsider thethis rule.

East Region

~~Illinois Union Insurance Company Litigation~~ Massachusetts Global Warming Solutions Act Proposed Regulation— 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,May 2016, the ~~U.S. District~~Massachusetts Supreme Judicial Court ~~granted LaGen's motion for attorney's fees of approximately $2 million for~~held that the ~~indemnity phase of the litigation. On January 29, 2016, ILU filed an appeal brief~~Massachusetts DEP had not complied with the ~~U.S.~~2008 Global Warming Solutions Act, which requires establishing limits for sources of GHGs. The Court held that participation in RGGI was not sufficient. In August 2017, the Massachusetts DEP finalized a regulation that, if it survives legal challenges, would limit GHG emissions, and may limit operations, from electric generating facilities located in Massachusetts. The final regulation has been challenged in The Commonwealth of Massachusetts Superior Court of Appeals for the Fifth Circuit. The 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. On March 21, 2017, the U.S. District Court issued an order extending the time for the parties to finalize a settlement until May 26, 2017.Suffolk County.

Significant Events

The following significant events have occurred during 2017, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

NRG Transformation Plan

On July 12, 2017, NRG announced its Transformation Plan. The three-part, three-year plan is comprised of targets in the areas of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement.

GenOn Chapter 11 Bankruptcy Filing

On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings and beginning on the Petition Date, NRG no longer consolidates GenOn for financial reporting purposes, as discussed in more detail in Note 1, Basis of Presentation, Note 3, Discontinued Operations, Dispositions and Acquisitions and Note 14, Related Party Transactionsof this Form 10-Q.

Transfers of Assets Under Common Control

On March 27, 2017, ~~the Company~~NRG completed the sale of the following projects to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, and (ii) NRG's interests in seven utility-scale solar projects located in Utah, which have reached commercial operations, for $130 million cash consideration, as discussed in more detail in Note 3, Discontinued Operations, Dispositions and Acquisitions~~to the Condensed Consolidated Financial Statements~~ of this Form 10-Q.

On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustments. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.

On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.

On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.

Financing Activities

On ~~February 28,~~May 26, 2017, ~~letters~~Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of ~~credit under NRG's revolving credit facility were drawn upon, which resulted in additional borrowings~~up to $407 million of ~~$125 million,~~senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, as discussed in more detail in Note 8, Debt and Capital Leases,.

On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of September 30, 2017, there were no cash borrowings outstanding on the revolver.

On October 16, 2017, NRG redeemed all of its outstanding 7.625% Senior Notes due 2018 and all of its outstanding 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest.

Operational Matters

Extreme Weather Events

In late August 2017, Hurricane Harvey made landfall on the Texas coast. During the third quarter of 2017, the Company’s Retail business was impacted by Hurricane Harvey by approximately $20 million.

In addition, during August 2017, NRG's Cottonwood generating station was damaged when the Sabine River Authority opened the floodgates of the Toledo Bend reservoir, which resulted in downstream flooding of the Sabine River. The generating station was returned to service during the fourth quarter of 2017. NRG is continuing to work with insurers on potential property insurance recovery and does not anticipate recovery from business interruption insurance due to the ~~Condensed Consolidated Financial Statements~~short period of ~~this Form 10-Q.~~

the outage. The Company estimates the impact of the Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.

~~Operational Matters~~

Carlsbad Energy Center Power Purchase Tolling Agreement

As of May 1, 2017, NRG’s subsidiary, Carlsbad Energy Center LLC, achieved the Conditions Precedent, or CP, ~~,Satisfaction~~Satisfaction Date under ~~the~~its power purchase tolling agreement with San Diego Gas & Electric Company for the Carlsbad Energy Center. The CP Satisfaction Date is the date on which specified conditions precedent under the power purchase tolling agreement have either been satisfied or waived.

~~Sherwin Bankruptcy~~Bacliff Project

~~The Company's Gregory cogeneration plant~~On June 16, 2017, the Company provided ~~steam, processed water and a small percentage of its electrical generation~~notice 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 ofBTEC New Albany, LLC that NRG 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 assertingPower LLC was exercising its right to ~~remain on its leasehold. A trial regarding~~terminate the ~~dispute was concluded on April 13, 2017. The parties await~~Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a ~~decision~~new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the ~~court. The~~contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.

Will County Unit 4

In May 2017, NRG's Will County Unit 4 suffered an equipment failure that is ~~currently evaluating potential options for~~projected to result in an extended outage. At this time, the ~~Gregory cogeneration plant.~~Company expects to complete repairs and return the unit to service in by early 2018.

Trends Affecting Results of Operations and Future Business Performance

~~The~~In addition to below, the Company’s trends are described in the Company’s 2016 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance.

ERCOT Retirements — A number of announced retirement notices of coal generating facilities in Texas could lower reserve margins in ERCOT. This trend of retirement notices could have an effect on the Company’s results of operations and future business performance, particularly in the ERCOT market.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended March 31,									Three months ended September 30,									Nine months ended September 30,
(In millions except otherwise noted)	2017			2016			Change			2017			2016			Change			2017			2016			Change
Operating Revenues
Energy revenue^(a)	$	826		$	1,151		$	(325	)	$	665		$	933		$	(268	)	$	1,908		$	2,478		$	(570	)
Capacity revenue ^(a)	384			513			(129		)	335			303			32			894			937			(43		)
Retail revenue	1,341			1,376			(35		)	1,934			2,015			(81		)	4,880			4,931			(51		)
Mark-to-market for economic hedging activities	128			26			102			26			62			(36		)	185			(360		)	545
Contract amortization	(15		)	(15		)	—			(12		)	(12		)	—			(41		)	(41		)	—
Other revenues ^(b)	95			178			(83		)	101			120			(19		)	306			383			(77		)
Total operating revenues	2,759			3,229			(470		)	3,049			3,421			(372		)	8,132			8,328			(196		)
Operating Costs and Expenses
Cost of sales ^(c)	1,404			1,505			101			1,679			1,847			168			4,362			4,526			164
Mark-to-market for economic hedging activities	134			(9		)	(143		)	50			149			99			168			(301		)	(469		)
Contract and emissions credit amortization ^(c)	(2		)	6			8			8			11			3			24			34			10
Operations and maintenance	485			588			103			326			354			28			1,038			1,196			158
Other cost of operations	104			104			—			93			79			(14		)	260			256			(4		)
Total cost of operations	2,125			2,194			69			2,156			2,440			284			5,852			5,711			141
Depreciation and amortization	300			313			13			272			298			26			789			826			37
Impairment losses										14			9			(5		)	77			65			(12		)
Selling, general and administrative	272			252			(20		)	213			277			64			697			801			104
Reorganization										18			—			(18		)	18			—			(18		)
Development costs	17			26			9			14			21			7			49			65			16
Total operating costs and expenses	2,714			2,785			71			2,687			3,045			358			7,482			7,468			(14		)
Gain on sale of assets	2			32			(30		)
Other income - affiliate										14			48			(34		)	104			144			(40		)
Gain/(loss) on sale of assets										—			4			(4		)	4			(79		)	83
Operating Income	47			476			(429		)	376			428			(52		)	758			925			(167		)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	5			(7		)	12
Equity in earnings of unconsolidated affiliates										27			16			11			29			13			16
Impairment loss on investment	—			(146		)	146			—			(8		)	8			—			(147		)	147
Other income, net	12			18			(6		)	15			7			8			33			29			4
(Loss)/gain on debt extinguishment, net	(2		)	11			(13		)
Loss on debt extinguishment, net										(1		)	(50		)	49			(3		)	(119		)	116
Interest expense	(269		)	(284		)	15			(221		)	(237		)	16			(692		)	(718		)	26
Total other expense	(254		)	(408		)	154			(180		)	(272		)	92			(633		)	(942		)	309
(Loss)/Income before Income Taxes	(207		)	68			(275		)
Income tax (benefit)/expense	(4		)	21			(25		)
Net (Loss)/Income	(203		)	47			(250		)
Income/(Loss) from Continuing Operations before Income Taxes										196			156			40			125			(17		)	142
Income tax expense										6			28			(22		)	5			75			(70		)
Income/(Loss) from Continuing Operations										190			128			62			120			(92		)	212
(Loss)/Income from discontinued operations, net of income tax										(27		)	265			(292		)	(802		)	256			(1,058		)
Net Income/(Loss)										163			393			(230		)	(682		)	164			(846		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	(40		)	(35		)	(5		)	(8		)	(9		)	1			(63		)	(49		)	(14		)
Net (Loss)/Income Attributable to NRG Energy, Inc.	$	(163	)	$	82		$	(245	)
Net Income/(Loss) Attributable to NRG Energy, Inc.										$	171		$	402		$	(231	)	$	(619	)	$	213		$	(832	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.32		$	2.09		59		%	$	3.00		$	2.81		7		%	$	3.17		$	2.29		38		%

(a) Includes realized gains and losses from financially settled transactions.

(b) Includes unrealized trading gains and losses.

Management’s discussion of the results of operations for the three months ended ~~March 31,~~September 30, 2017 and 2016

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 ~~March 31,~~September 30, 2017 and 2016. The average on-peak power prices have generally ~~increased~~decreased primarily due to the increase in natural gas prices for the three months ended ~~March 31,~~September 30, 2017 as compared to the same period in 2016.

Average on Peak Power Price ($/MWh) ^(a)
Three months ended March 31,
Region 2017 2016 Change %
Gulf Coast ^(b)

ERCOT - Houston $ 27.70
$ 20.45
35 %
ERCOT - North 22.76
19.64
16 %
MISO - Louisiana Hub 44.77
23.50
91 %
East
    NY J/NYC 35.59
33.30
7 %
    NY A/West NY 27.61
30.27
(9 )%
    NEPOOL 33.92
30.82
10 %
    PEPCO (PJM) 33.72
34.36
(2 )%
    PJM West Hub 31.96
30.30
5 %
West
CAISO - NP15 26.54
23.92
11 %
CAISO - SP15 23.08
23.32
(1 )%



	Average on Peak Power Price ($/MWh)
	Three months ended September 30,
Region	2017		2016		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	33.09	$	33.12	—	%
ERCOT - North^(b)	29.35		30.47		(4	)%
MISO - Louisiana Hub^(c)	39.56		39.83		(1	)%
East/West
NY J/NYC^(c)	37.42		42.50		(12	)%
NEPOOL^(c)	31.94		42.33		(25	)%
PEPCO (PJM)^(c)	38.81		42.57		(9	)%
PJM West Hub^(c)	35.10		38.84		(10	)%
CAISO - NP15^(c)	46.69		38.13		22	%
CAISO - SP15^(c)	46.54		40.24		16	%

(a) Gulf Coast region also transacts in PJM - West Hub.

(b) 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.~~(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended ~~March 31,~~September 30, 2017 and 2016, which reflects the impact of settled hedges.


	Average Realized Power Price ($/MWh)						Average Realized Power Price ($/MWh)
	Three months ended March 31,						Three months ended September 30,
Region	2017		2016		Change %		2017		2016		Change %
Gulf Coast	$	33.05	$	38.60	(14	)%	$	34.69	$	39.68	(13	)%
East	50.85		52.33		(3	)%
West	44.49		32.83		36	%
East/West							38.19		40.44		(6	)%

Though the average on peak power prices have ~~increased~~decreased on average by ~~14%~~5%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.

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, retail revenue and other revenue, less cost of fuels and other cost of sales.

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 ~~March 31,~~September 30, 2017 and 2016:


	Three months ended March 31, 2017																																Three months ended September 30, 2017
	Generation																																Generation
(In millions)	Gulf Coast			East			West			Other		Eliminations			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total			Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	412		$	411		$	23		$	1	$	—		$	847		$	—		$	72		$	114		$	(207	)	$	826		$	540		$	243		$	783		$	—		$	119		$	146		$	(383	)	$	665
Capacity revenue	66			217			27			—		—			310			—			—			79			(5		)	384			74			172			246			—			1			92			(4		)	335
Retail revenue	—			—			—			—		—			—			1,334			—			—			7			1,341			—			—			—			1,936			—			—			(2		)	1,934
Mark-to-market for economic hedging activities	130			(2		)	4			—		—			132			2			6			—			(12		)	128			133			—			133			—			5			—			(112		)	26
Contract amortization	3			—			—			—		—			3			(1		)	—			(17		)	—			(15		)	5			—			5			1			(1		)	(18		)	1			(12		)
Other revenue ^(a)(b)	50			(2		)	1			5		(3		)	51			—			20			42			(18		)	95			41			16			57			—			20			44			(20		)	101
Operating revenue	661			624			55			6		(3		)	1,343			1,335			98			218			(235		)	2,759			793			431			1,224			1,937			144			264			(520		)	3,049
Cost of fuel	(237		)	(187		)	(14		)	—		—			(438		)	(5		)	(1		)	(12		)	26			(430		)	(292		)	(123		)	(415		)	(1		)	(1		)	(6		)	17			(406		)
Other cost of sales^(b)(c)	(81		)	(77		)	(4		)	—		—			(162		)	(992		)	(3		)	(4		)	187			(974		)	(102		)	(79		)	(181		)	(1,457		)	(3		)	(9		)	377			(1,273		)
Mark-to-market for economic hedging activities	(9		)	(1		)	3			—		—			(7		)	(139		)	—			—			12			(134		)	2			10			12			(174		)	—			—			112			(50		)
Contract and emission credit amortization	(5		)	5			2			—		—			2			—			—			—			—			2			(7		)	(1		)	(8		)	—			—			—			—			(8		)
Gross margin	$	329		$	364		$	42		$	6	$	(3	)	$	738		$	199		$	94		$	202		$	(10	)	$	1,223		$	394		$	238		$	632		$	305		$	140		$	249		$	(14	)	$	1,312
Less: Mark-to-market for economic hedging activities, net	121			(3		)	7			—		—			125			(137		)	6			—			—			(6		)	135			10			145			(174		)	5			—			—			(24		)
Less: Contract and emission credit amortization, net	(2		)	5			2			—		—			5			(1		)	—			(17		)	—			(13		)	(2		)	(1		)	(3		)	1			(1		)	(18		)	1			(20		)
Economic gross margin	$	210		$	362		$	33		$	6	$	(3	)	$	608		$	337		$	88		$	219		$	(10	)	$	1,242		$	261		$	229		$	490		$	478		$	136		$	267		$	(15	)	$	1,356
Business Metrics
MWh sold (thousands)^(d)(e)	12,467			8,082			517														930			1,662									15,568			6,363									928			1,544
MWh generated (thousands)^(e)(f)	11,783			5,921			517														930			1,804									14,185			4,106									928			2,261
(a) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits
(c) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(d) Does not include thermal MWh of 9 thousand or MWt of 569 thousand for thermal sold by NRG Yield.
(e) Does not include thermal MWh of 16 thousand or MWt of 569 thousand for thermal generated by NRG Yield.
(a) Includes International, BETM and Generation eliminations																																	(a) Includes International, BETM and Generation eliminations
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.																																	(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits																																	(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.																																	(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 463 thousand for thermal sold by NRG Yield.																																	(e) Does not include thermal MWh of 9 thousand or MWt of 463 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 44 thousand or MWt of 463 thousand for thermal generated by NRG Yield.																																	(f) Does not include thermal MWh of 44 thousand or MWt of 463 thousand for thermal generated by NRG Yield.


	Three months ended March 31, 2016																																Three months ended September 30, 2016
	Generation																																Generation
(In millions)	Gulf Coast			East			West			Other		Eliminations			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total			Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	468		$	605		$	28		$	28	$	—		$	1,129		$	—		$	85		$	129		$	(192	)	$	1,151		$	650		$	362		$	1,012		$	—		$	127		$	158		$	(364	)	$	933
Capacity revenue	78			324			39			—		—			441			—			—			83			(11		)	513			72			148			220			—			—			86			(3		)	303
Retail revenue	—			—			—			—		—			—			1,371			—			—			5			1,376			—			—			—			2,009			—			—			6			2,015
Mark-to-market for economic hedging activities	(28		)	31			—			—		—			3			—			1			—			22			26			179			57			236			2			1			—			(177		)	62
Contract amortization	3			—			—			—		—			3			(1		)	—			(17		)	—			(15		)	4			—			4			1			(1		)	(17		)	1			(12		)
Other revenue ^(a)(b)	56			17			50			13		(4		)	132			—			10			39			(3		)	178			51			13			64			—			12			45			(1		)	120
Operating revenue	577			977			117			41		(4		)	1,708			1,370			96			234			(179		)	3,229			956			580			1,536			2,012			139			272			(538		)	3,421
Cost of fuel	(192		)	(242		)	(13		)	—		—			(447		)	(4		)	(1		)	(11		)	58			(405		)	(317		)	(190		)	(507		)	(1		)	(2		)	(7		)	18			(499		)
Other cost of sales^(b)(c)	(88		)	(126		)	(5		)	—		—			(219		)	(1,021		)	(1		)	(5		)	146			(1,100		)	(114		)	(83		)	(197		)	(1,484		)	(1		)	(11		)	345			(1,348		)
Mark-to-market for economic hedging activities	2			(1		)	(3		)	—		—			(2		)	33			—			—			(22		)	9			27			7			34			(360		)	—			—			177			(149		)
Contract and emission credit amortization	(5		)	5			(1		)	—		—			(1		)	(2		)	—			(6		)	3			(6		)	(9		)	—			(9		)	(2		)	—			—			—			(11		)
Gross margin	$	294		$	613		$	95		$	41	$	(4	)	$	1,039		$	376		$	94		$	212		$	6		$	1,727		$	543		$	314		$	857		$	165		$	136		$	254		$	2		$	1,414
Less: Mark-to-market for economic hedging activities, net	(26		)	30			(3		)	—		—			1			33			1			—			—			35			206			64			270			(358		)	1			—			—			(87		)
Less: Contract and emission credit amortization, net	(2		)	5			(1		)	—		—			2			(3		)	—			(23		)	3			(21		)	(5		)	—			(5		)	(1		)	(1		)	(17		)	1			(23		)
Economic gross margin	$	322		$	578		$	99		$	41	$	(4	)	$	1,036		$	346		$	93		$	235		$	3		$	1,713		$	342		$	250		$	592		$	524		$	136		$	271		$	1		$	1,524
Business Metrics
MWh sold (thousands)^(d)(e)	12,123			11,561			853														1,089			1,778									16,380			8,951									977			1,744
MWh generated (thousands)^(e)(f)	10,861			8,295			724														1,089			2,039									14,927			6,426									977			2,372
(a) Renewables other revenue includes $4 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits
(c) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(d) Does not include thermal MWh of 40 thousand or MWt of 553 thousand for thermal sold by NRG Yield.
(e) Does not include thermal MWh of 91 thousand or MWt of 553 thousand for thermal generated by NRG Yield.
(a) Includes International, BETM and Generation eliminations.																																	(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $5 million of intercompany revenue to NRG Yield.																																	(b) Renewables other revenue includes $5 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits																																	(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.																																	(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield.																																	(e) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 125 thousand or MWt of 496 thousand for thermal generated by NRG Yield.																																	(f) Does not include thermal MWh of 125 thousand or MWt of 496 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the three months ended ~~March 31,~~September 30, 2017 and 2016:


	Three months ended March 31,			Three months ended September 30,
Weather Metrics	Gulf Coast	East	West	Gulf Coast	East/West
2017
CDDs ^(a)	204	37	3	1,528	770
HDDs ^(a)	631	2,137	1,119	1	34
2016
CDDs	76	33	5	1,655	806
HDDs	931	2,251	974	—	23
10 year average
CDDs	81	32	3	1,617	705
HDDs	1,086	2,487	1,111	6	40

(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.

Generation gross margin and economic gross margin

~~The below tables present the changes in~~ Generation gross margin decreased $225 million and economic gross margin decreased $102 million, both of which include intercompany sales, during the three months ended ~~March 31,~~September 30, 2017, compared to the same period in 2016:

(In millions) Gross Margin increase/(decrease) Economic Gross Margin increase/(decrease)
Gulf Coast region $ 35
$ (112 )
East region (249 ) (216 )
West region (53 ) (66 )
Other (35 ) (35 )
$ (302 ) $ (429 )

The ~~tables~~table below ~~describe~~describes the decrease in Generation gross margin and economic gross ~~margin by region:~~margin:

Gulf Coast Region

(In millions)
Lower gross margin due to lower average realized prices primarily in Texas due to lower hedged power prices $ (101 )
Lower gross margin primarily due to contract expirations and lower demand (15 )
Lower gross margin due to a 66% decrease in ISO capacity prices and a 14% decrease in capacity volume (14 )
Lower gross margin due to increased supply costs on load contracts (8 )
Lower gross margin resulting from an 8% decrease in nuclear generation driven by the timing of planned outages (7 )
Higher gross margin primarily due to higher coal generation mainly in Texas which was driven by the timing of planned outages 31
Other 2
Decrease in economic gross margin $ (112 )
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 147
Increase in gross margin $ 35



	(In millions)
Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices	$	(76	)
Lower energy margin due to increased supply cost on load contracts	(13		)
Lower capacity margin on contract expirations and lower demand	(9		)
Higher gross margin due to increased generation primarily due to lower unplanned outages	16
Other	1
Decrease in economic gross margin	$	(81	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(71		)
Increase in contract and emission credit amortization	3
Decrease in gross margin	$	(149	)

~~East Region~~East/West

(In millions)
Lower gross margin due to a 43% decrease in New York and New England hedged capacity prices and a 32% decrease in PJM cleared auction capacity prices $ (77 )
Lower gross margin due to a 30% decrease in generation as a result of deactivating the Huntley and Dunkirk facilities in 2016, the sale of the Seward, Aurora and Shelby generating stations in 2016, as well as milder winter weather conditions in 2017 (55 )
Lower gross margin due to a 32% increase in the price of natural gas and transportation costs due to less favorable short-term natural gas contract terms, as well as a 2% decrease in average realized energy prices (35 )
Lower gross margin due to higher supply costs for servicing certain load contracts (22 )
Lower gross margin due to lower contracted volumes and prices in New York (17 )
Changes in commercial optimization activities (17 )
Higher gross margin due to fewer outage hours primarily in PJM, due to unit conversions and deactivations 12
Other (5 )
Decrease in economic gross margin $ (216 )
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (33 )
Decrease in gross margin $ (249 )



	(In millions)
Lower gross margin due to a 37% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage	$	(28	)
Lower gross margin from commercial optimization activities	(8		)
Higher gross margin due to a 38% increase in PJM capacity volumes coupled with a 140% increase in NY/NE realized capacity prices	21
Higher gross margin due to a 12% increase in average realized energy prices due to extreme heat in California and increased pricing during high demand periods in the East	10
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies	(16		)
Decrease in economic gross margin	$	(21	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(54		)
Decrease in contract and emission credit amortization	(1		)
Decrease in gross margin	$	(76	)

~~West Region~~

(In millions)
Lower gross margin due to the gain on sale of excess emission credits in 2016 $ (47 )
Lower gross margin due to a 45% decrease in capacity volume primarily due to the retirement of the Pittsburg generating station, partially offset by a 14% increase in capacity prices (16 )
Other (3 )
Decrease in economic gross margin $ (66 )
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 10
Increase in contract and emission credit amortization 3
Decrease in gross margin $ (53 )

~~Other~~

Other gross margin and economic gross margin both decreased $35 million for the three months ended March 31, 2017, compared to the same period in 2016, due to BETM losses on both over the counter and congestion strategies.

Retail gross margin and economic gross margin

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


	Three months ended March 31,						Three months ended September 30,
(In millions except otherwise noted)	2017			2016			2017			2016
Retail revenue	$	1,295		$	1,340		$	1,845		$	1,911
Supply management revenue	33			24			63			53
Capacity revenue	6			7			28			45
Customer mark-to-market	2			—			—			2
Contract amortization	(1		)	(1		)	1			1
Operating revenue^(a)	1,335			1,370			1,937			2,012
Cost of sales ^(b)	(997		)	(1,025		)	(1,458		)	(1,485		)
Mark-to-market for economic hedging activities	(139		)	33			(174		)	(360		)
Contract amortization	—			(2		)	—			(2		)
Gross Margin	$	199		$	376		$	305		$	165
Less: Mark-to-market for economic hedging activities, net	(137		)	33			(174		)	(358		)
Less: Contract and emission credit amortization, net	(1		)	(3		)	1			(1		)
Economic Gross Margin	$	337		$	346		$	478		$	524

Business Metrics
Mass electricity sales volume - GWh - Gulf Coast	6,984			6,713			11,935			11,996
Mass electricity sales volume - GWh - All other regions	1,641			1,834			1,724			1,986
C&I electricity sales volume — GWh - All regions	4,833			4,540			5,087			5,146
Natural gas sales volumes (MDth)	1,262			923			241			172
Average Retail Mass customer count (in thousands)	2,826			2,760			2,884			2,786
Ending Retail Mass customer count (in thousands)	2,832			2,759			2,880			2,797


(a)	Includes intercompany sales of $1$2 million and $3$1 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of ~~$209~~$365 million and ~~$192~~$340 million in 2017 and 2016, respectively.

Retail gross margin ~~decreased $177~~increased $140 million and economic gross margin decreased $9$46 million for the three months ended ~~March 31,~~September 30, 2017, compared to the same period in 2016, due to:

(In millions)
Weather driven gross margin is lower by $12 million due to a reduction in load of 308,000 MWhs and $7 million in lower margin due to the unfavorable impacts of selling back excess supply in 2017 as compared to 2016 $ (19 )
Lower gross margin due to lower rates to customers of $54 million, or approximately $6 per MWh, partially offset by lower supply costs of $45 million, or approximately $5 per MWh driven primarily by a decrease in power prices at the time of procurement (9 )
Higher gross margin due to higher volumes driven by higher average customer usage and mix and an increase in customer count 19
Decrease in economic gross margin $ (9 )
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (170 )
Increase in contract and emission credit amortization 2
Decrease in gross margin $ (177 )



	(In millions)
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $26 million or approximately $1.25 per MWh and higher supply costs of $10 million or approximately $0.50 per MWh driven primarily by an increase in power prices at the time of procurement	$	(36	)
Lower gross margin of $15 million due to a reduction in load of 477,000 MWh partially offset by $4 million in higher margin due to the lower unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016	(11		)
Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017	(16		)
Higher gross margin due to higher volumes driven by higher average customer usage and mix	17
Decrease in economic gross margin	$	(46	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	184
Increase in contract and emission credit amortization	2
Increase in gross margin	$	140

~~NRG Yield gross margin and economic gross margin~~

NRG Yield gross margin decreased $10 million and economic gross margin decreased $16 million for the three months ended March 31, 2017, compared to the same period in 2016, due to a 17% decrease in volume generated at the Alta Wind projects due to low wind resources as well as a 14% decrease in solar generation at solar projects caused by weather.

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~~increased by ~~$41~~$63 million during the three months ended ~~March 31,~~September 30, 2017, compared to the same period in 2016.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:

Three months ended March 31, 2017
Generation
Gulf Coast East West Retail Renewables
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 $ —
$ (20 ) $ (1 ) $ —
$ —
$ 40
$ 19
Reversal of acquired loss positions related to economic hedges —
2
—
—
—
—
2
Net unrealized gains/(losses) on open positions related to economic hedges 130
16
5
2
6
(52 ) 107
Total mark-to-market gains/(losses) in operating revenues $ 130
$ (2 ) $ 4
$ 2
$ 6
$ (12 ) $ 128
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges $ (3 ) $ 6
$ 3
$ 31
$ —
$ (40 ) $ (3 )
Net unrealized (losses)/gains on open positions related to economic hedges (6 ) (7 ) —
(170 ) —
52
(131 )
Total mark-to-market (losses)/gains in operating costs and expenses $ (9 ) $ (1 ) $ 3
$ (139 ) $ —
$ 12
$ (134 )


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


	Three months ended March 31, 2016																				Three months ended September 30, 2017
	Generation																				Generation
	Gulf Coast			East			West			Retail			Renewables		Elimination^(a)			Total			Gulf Coast			East/West			Retail			Renewables		Eliminations^(a)			Total
	(In millions)																				(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges																					$	121		$	5		$	—		$	1	$	(68	)	$	59
Net unrealized gains/(losses) on open positions related to economic hedges																					12			(5		)	—			4		(44		)	(33		)
Total mark-to-market gains/(losses) in operating revenues																					$	133		$	—		$	—		$	5	$	(112	)	$	26
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(139	)	$	(134	)	$	(1	)	$	—		$	—	$	43		$	(231	)	$	(5	)	$	(1	)	$	(127	)	$	—	$	68		$	(65	)
Reversal of acquired gain positions related to economic hedges	—			(11		)	—			—			—		—			(11		)	—			—			(2		)	—		—			(2		)
Net unrealized gains/(losses) on open positions related to economic hedges	111			176			1			—			1		(21		)	268			7			11			(45		)	—		44			17
Total mark-to-market (losses)/gains in operating revenues	$	(28	)	$	31		$	—		$	—		$	1	$	22		$	26
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	11		$	36		$	(1	)	$	142		$	—	$	(43	)	$	145
Reversal of acquired gain positions related to economic hedges	—			—			(2		)	—			—		—			(2		)
Net unrealized (losses)/gains on open positions related to economic hedges	(9		)	(37		)	—			(109		)	—		21			(134		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	2		$	(1	)	$	(3	)	$	33		$	—	$	(22	)	$	9		$	2		$	10		$	(174	)	$	—	$	112		$	(50	)


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



	Three months ended September 30, 2016
	Generation
	Gulf Coast		East/West			Retail			Renewables		Eliminations^(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	$	(1	)	$	—		$	—	$	(77	)	$	(70	)
Net unrealized gains/(losses) on open positions related to economic hedges	171		58			2			1		(100		)	132
Total mark-to-market gains/(losses) in operating revenues	$	179	$	57		$	2		$	1	$	(177	)	$	62
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	7	$	2		$	(46	)	$	—	$	77		$	40
Reversal of acquired gain positions related to economic hedges	—		(5		)	(2		)	—		—			(7		)
Net unrealized gains/(losses) on open positions related to economic hedges	20		10			(312		)	—		100			(182		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	27	$	7		$	(360	)	$	—	$	177		$	(149	)


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

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 ~~March 31,~~September 30, 2017,, the ~~$128~~$26 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 a decrease in value of open positions as a result of an increase in natural gas prices. The $50 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, partially offset by an increase in value of open positions as a result of an increase in coal prices.

For the three months ended September 30, 2016, the $62 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in ~~natural~~ gas and ~~ERCOT~~ electricity prices, ~~as well as~~partially offset by the reversal of previously recognized unrealized ~~losses~~gains on contracts that settled during the ~~period and the reversal of acquired contracts.~~period. The ~~$134~~$149 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 ~~coal,~~ and ERCOT electricity ~~prices.~~

For the three months ended March 31, 2016, the $26 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in electricity prices, ~~largely~~partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts. The $9 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, largely offset by a decrease in value of open positions as a result of decreases in natural gas, coal, and ERCOT electricity prices.~~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 three months ended ~~March 31,~~September 30, 2017 and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. 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 March 31,					Three months ended September 30,
(In millions)	2017			2016		2017			2016
Trading gains/(losses)
Trading (losses)/gains
Realized	$	14		$	24	$	(10	)	$	20
Unrealized	(14		)	19		(5		)	(5		)
Total trading gains	$	—		$	43
Total trading (losses)/gains						$	(15	)	$	15

Operations and Maintenance Expense

Generation Retail Renewables NRG Yield Corporate Eliminations Total
Gulf Coast East West Other Eliminations
(In millions)
Three months ended March 31, 2017 $ 146
$ 187
$ 27
$ —
$ (3 ) $ 59
$ 29
$ 51
$ (1 ) $ (10 ) $ 485
Three months ended March 31, 2016 $ 144
$ 272
$ 36
$ —
$ (4 ) $ 60
$ 33
$ 44
$ 9
$ (6 ) $ 588



	Generation				Retail		Renewables		NRG Yield		Corporate		Eliminations			Total
	Gulf Coast		East/West^(a)		Retail		Renewables		NRG Yield		Corporate		Eliminations			Total
	(In millions)
Three months ended September 30, 2017	$	120	$	85	$	56	$	28	$	46	$	3	$	(12	)	$	326
Three months ended September 30, 2016	139		97		58		19		41		7		(7		)	354


(a)	Includes International, BETM and generation eliminations of $2 million in 2017 and $1 million in 2016.

Operations and maintenance expense decreased by ~~$103~~$28 million for the three months ended ~~March 31,~~September 30, 2017, compared to the same period in 2016, due to the following:



	(In millions)
Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas	$	(18	)
Decrease in operation and maintenance expenses primarily due to major maintenance activities and environmental work at Midwest Generation in 2016	(11		)
Other	1
	$	(28	)

Selling, General and Administrative

Selling, general and administrative expenses are comprised of the following:



	Generation		Retail		Renewables		NRG Yield		Corporate		Total
	(In millions)
Three months ended September 30, 2017	$	42	$	112	$	14	$	4	$	41	$	213
Three months ended September 30, 2016	64		137		12		4		60		277

Selling, general and administrative expenses decreased by $64 million for the three months ended September 30, 2017, compared to the same period in 2016. The decrease in year over year expenses is due primarily to a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.

Reorganization

Reorganization expenses of $18 million were incurred during the third quarter of 2017 related to the Transformation Plan announced on July 12, 2017.

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 $16 million for the three months ended September 30, 2017, compared to the same period in 2016 due to the following:



	(In millions)
Decrease due to the repurchase of Senior Notes in 2016 of $25 million, partly offset by Senior Notes issued in 2016 of $7 million	$	(18	)
Decrease due to termination of swaps related to 2016 Capistrano debt refinancing	(16		)
Increase due to the issuance of Carlsbad Energy Project debt during 2017, and Utah Portfolio debt, due 2022, during 2016	8
Increase in derivative interest expense from changes in fair value of interest rate swaps	4
Increase due to the issuance of Yield Operating Senior Notes, due 2026	3
Other	3
	$	(16	)

Income Tax Expense

For the three months ended September 30, 2017, NRG recorded income tax expense of $6 million on pre-tax income of $196 million. For the same period in 2016, NRG recorded income tax expense of $28 million on pre-tax income of $156 million. The effective tax rate was 3.1% and 17.9% for the three months ended September 30, 2017 and 2016, respectively.

For the three months ended September 30, 2017, NRG's overall effective tax rate was different then the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.

(Loss)/Income from Discontinued Operations, Net of Income Tax Expense/(Benefit)

For the three months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax expense/(benefit) of $27 million.

For the three months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax expense/(benefit) of $265 million.

Management’s discussion of the results of operations for the nine months ended September 30, 2017, and 2016

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, 2017, and 2016. Average on-peak power prices increased primarily due to the increase in natural gas prices for the nine months ended September 30, 2017 as compared to the same period in 2016.



	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2017		2016		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	35.61	$	25.97	37	%
ERCOT - North^(b)	26.64		24.14		10	%
MISO - Louisiana Hub^(c)	42.33		33.47		26	%
East/West
NY J/NYC^(c)	37.46		35.04		7	%
NEPOOL^(c)	33.11		33.80		(2	)%
PEPCO (PJM)^(c)	35.65		38.15		(7	)%
PJM West Hub^(c)	33.30		33.95		(2	)%
CAISO - NP15^(c)	33.82		29.38		15	%
CAISO - SP15^(c)	33.42		30.22		11	%

(a) Gulf Coast region also transacts in PJM - West Hub.

(b) Average on peak power prices based on real time settlement prices as published by the respective ISOs.

The following table summarizes average realized power prices for each region in which NRG operates for the nine months ended September 30, 2017, and 2016, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Nine months ended September 30,
Region	2017		2016		Change %
Gulf Coast	$	34.42	$	39.52	(13	)%
East/West	40.33		42.38		(5	)%

Though the average on peak power prices have increased on average by 7%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.

Gross Margin

Economic Gross Margin

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, 2017 and 2016:



	Nine months ended September 30, 2017
	Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	1,408		$	651		$	2,059		$	—		$	298		$	436		$	(885	)	$	1,908
Capacity revenue	207			438			645			—			1			256			(8		)	894
Retail revenue	—			—			—			4,875			—			—			5			4,880
Mark-to-market for economic hedging activities	174			4			178			—			8			—			(1		)	185
Contract amortization	11			—			11			—			(1		)	(52		)	1			(41		)
Other revenue ^(b)	143			36			179			—			58			127			(58		)	306
Operating revenue	1,943			1,129			3,072			4,875			364			767			(946		)	8,132
Cost of fuel	(790		)	(293		)	(1,083		)	(8		)	(3		)	(24		)	48			(1,070		)
Other cost of sales^(c)	(259		)	(203		)	(462		)	(3,661		)	(8		)	(21		)	860			(3,292		)
Mark-to-market for economic hedging activities	(22		)	7			(15		)	(154		)	—						1			(168		)
Contract and emission credit amortization	(21		)	(3		)	(24		)	—			—						—			(24		)
Gross margin	$	851		$	637		$	1,488		$	1,052		$	353		$	722		$	(37	)	$	3,578
Less: Mark-to-market for economic hedging activities, net	152			11			163			(154		)	8			—			—			17
Less: Contract and emission credit amortization, net	(10		)	(3		)	(13		)	—			(1		)	(52		)	1			(65		)
Economic gross margin	$	709		$	629		$	1,338		$	1,206		$	346		$	774		$	(38	)	$	3,626
Business Metrics
MWh sold (thousands)^(d)(e)	40,908			16,140									2,940			5,295
MWh generated (thousands)^(f)	37,975			10,202									2,940			6,467
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $21 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 27 thousand or MWt of 1,450 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 80 thousand or MWt of 1,450 thousand for thermal generated by NRG Yield.



	Nine months ended September 30, 2016
	Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	1,598		$	896		$	2,494		$	—		$	303		$	459		$	(778	)	$	2,478
Capacity revenue	222			468			690			—			—			256			(9		)	937
Retail revenue	—			—			—			4,918			—			—			13			4,931
Mark-to-market for economic hedging activities	(270		)	(9		)	(279		)	—			—			—			(81		)	(360		)
Contract amortization	11			—			11			—			(1		)	(51		)	—			(41		)
Other revenue ^(b)	182			75			257			—			34			125			(33		)	383
Operating revenue	1,743			1,430			3,173			4,918			336			789			(888		)	8,328
Cost of fuel	(718		)	(371		)	(1,089		)	(5		)	(3		)	(25		)	114			(1,008		)
Other cost of sales^(c)	(309		)	(245		)	(554		)	(3,628		)	(9		)	(23		)	696			(3,518		)
Mark-to-market for economic hedging activities	62			8			70			150			—			—			81			301
Contract and emission credit amortization	(22		)	(4		)	(26		)	(5		)	—			(6		)	3			(34		)
Gross margin	$	756		$	818		$	1,574		$	1,430		$	324		$	735		$	6		$	4,069
Less: Mark-to-market for economic hedging activities, net	(208		)	(1		)	(209		)	150			—			—			—			(59		)
Less: Contract and emission credit amortization, net	(11		)	(4		)	(15		)	(5		)	(1		)	(57		)	3			(75		)
Economic gross margin	$	975		$	823		$	1,798		$	1,285		$	325		$	792		$	3		$	4,203
Business Metrics
MWh sold (thousands)^(d)(e)	40,433			21,141									2,968			5,563
MWh generated (thousands)^(f)	36,427			13,732									2,968			6,828
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 61 thousand or MWt of 1,497 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 248 thousand or MWt of 1,497 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the nine months ended September 30, 2017 and 2016:



	Nine months ended September 30,
Weather Metrics	Gulf Coast	East/West
2017
CDDs ^(a)	2,653	1,071
HDDs ^(a)	674	2,041
2016
CDDs	2,605	1,098
HDDs	984	2,046
10 year average
CDDs	2,656	976
HDDs	1,167	2,277

(a)

Generation gross margin and economic gross margin

Generation gross margin decreased $86 million and economic gross margin decreased $460 million, both of which include intercompany sales, during the nine months ended September 30, 2017, compared to the same period in 2016:

The tables below describe the decrease in Generation gross margin and economic gross margin:

Gulf Coast Region



	(In millions)
Lower gross margin due to a 12% decrease in average realized prices primarily in Texas due to lower hedged power prices	$	(225	)
Lower energy margin due to increased supply costs on load contracts	(39		)
Lower capacity margin on contract expirations and lower demand	(29		)
Lower gross margin due to a 42% decrease in ISO capacity prices and a 58% decrease in volume	(18		)
Lower gross margin from a 7% decrease in nuclear generation driven by the timing of planned outages	(17		)
Higher gross margin primarily due to 19% higher coal generation mainly in Texas driven by timing of planned outages	59
Other	3
Decrease in economic gross margin	$	(266	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	360
Increase in contract and emission credit amortization	1
Increase in gross margin	$	95

East/West



	(In millions)
Lower gross margin due to a 14% decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage	$	(60	)
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 on congestion strategies	(45		)
Lower gross margin from commercial optimization activities	(39		)
Lower gross margin due to lower load contracted prices coupled with slightly lower volumes	(26		)
Lower gross margin due to a 16% decrease in capacity pricing in New York of $10 million coupled with decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration and unit retirements in California	(23		)
Other	(1		)
Decrease in economic gross margin	$	(194	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	12
Increase in contract and emission credit amortization	1
Decrease in gross margin	$	(181	)

Retail gross margin and economic gross margin

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



	Nine months ended September 30,
(In millions except otherwise noted)	2017			2016
Retail revenue	$	4,658		$	4,727
Supply management revenue	147			117
Capacity revenue	70			74
Operating revenue^(a)	4,875			4,918
Cost of sales ^(b)	(3,669		)	(3,633		)
Mark-to-market for economic hedging activities	(154		)	150
Contract amortization	—			(5		)
Gross Margin	$	1,052		$	1,430
Less: Mark-to-market for economic hedging activities, net	(154		)	150
Less: Contract and emission credit amortization, net	—			(5		)
Economic Gross Margin	$	1,206		$	1,285

Business Metrics
Mass electricity sales volume - GWh - Gulf Coast	28,153			27,382
Mass electricity sales volume - GWh - All other regions	4,722			5,264
C&I electricity sales volume — GWh - All regions ^(c)	15,228			14,357
Natural gas sales volumes (MDth)	1,941			1,423
Average Retail Mass customer count (in thousands)	2,857			2,770
Ending Retail Mass customer count (in thousands)	2,880			2,797


(a)	Includes intercompany sales of $4 million and $3 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $830 million and $655 million in 2017 and 2016.


(c)	Includes volumes for 2017 for one customer that self-supplied their volumes during the first six months of 2016.

Retail gross margin decreased $378 million and economic gross margin decreased $79 million for the nine months ended September 30, 2017, compared to the same period in 2016, due to:



	(In millions)
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $95 million or approximately $2 per MWh, partially offset by lower supply costs of $5 million or approximately $0.10 per MWh driven primarily by a decrease in power prices at the time of procurement	$	(90	)
Lower gross margin of $9 million due to a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief related to the impact of Hurricane Harvey in 2017	(16		)
Lower gross margin of $13 million due to a reduction in load of 420,000 MWh and $2 million in lower margin due to the unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 as compared to 2016	(15		)
Higher gross margin due to higher volumes driven by higher average customer usage and mix	42
Decrease in economic gross margin	$	(79	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(304		)
Increase in contract and emission credit amortization	5
Decrease in gross margin	$	(378	)

Renewables gross margin and economic gross margin

Renewables gross margin increased $29 million and economic gross margin increased $21 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily ~~due to an $85~~driven by new distributed generation solar projects placed in service, increased margin in operations and maintenance agreements and receipt of insurance proceeds offsetting lower volume at the Ivanpah solar plant.

NRG Yield gross margin and economic gross margin

NRG Yield gross margin decreased $13 million ~~decrease in expenses in the East region as a result of fewer planned outages, less deactivation activity, sales of facilities in 2016,~~ and ~~a decrease in expenses due to environmental control and fuel conversion expenses incurred in 2016. In addition, expenses for the West region~~economic gross margin decreased by $9$19 million ~~primarily due to~~during the ~~timing of planned outages.~~

~~Depreciation and Amortization~~

~~Depreciation and amortization expense decreased by $13 million for the three~~nine months ended ~~March 31,~~September 30, 2017,, compared to the same period in 2016,~~, primarily~~ due to a 4% decrease in ~~depreciation~~volume generated at wind projects, primarily in connection with lower wind resources at the Alta Wind and NRG Wind TE Holdco projects, as well as 5% decrease in solar generation, primarily at CVSR in connection with lower insolation.

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 $76 million during the nine months ended September 30, 2017, compared to the same period in 2016.

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, 2017
	Generation
	Gulf Coast			East/West			Retail			Renewables		Eliminations^(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	$	113		$	(32	)	$	(1	)	$	1	$	21		$	102
Net unrealized gains/(losses) on open positions related to economic hedges	61			36			1			7		(22		)	83
Total mark-to-market gains/(losses) in operating revenues	$	174		$	4		$	—		$	8	$	(1	)	$	185
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(12	)	$	1		$	(51	)	$	—	$	(21	)	$	(83	)
Reversal of acquired gain positions related to economic hedges	—			—			(1		)	—		—			(1		)
Net unrealized (losses)/gains on open positions related to economic hedges	(10		)	6			(102		)	—		22			(84		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(22	)	$	7		$	(154	)	$	—	$	1		$	(168	)


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



	Nine months ended September 30, 2016
	Generation
	Gulf Coast			East/West			Retail			Renewables		Eliminations^(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	)	$	(68	)	$	(1	)	$	—	$	—		$	(329	)
Net unrealized (losses)/gains on open positions related to economic hedges	(10		)	59			1			—		(81		)	(31		)
Total mark-to-market losses in operating revenues	$	(270	)	$	(9	)	$	—		$	—	$	(81	)	$	(360	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	26		$	10		$	218		$	—	$	—		$	254
Reversal of acquired gain positions related to economic hedges	—			(10		)	(1		)	—		—			(11		)
Net unrealized gains/(losses) on open positions related to economic hedges	36			8			(67		)	—		81			58
Total mark-to-market gains in operating costs and expenses	$	62		$	8		$	150		$	—	$	81		$	301


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

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, 2017, the $185 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, as well as an increase in value of open positions as a result of decreases in PJM power prices, New York capacity prices, and natural gas prices. The $168 million loss in operating costs and expenses from economic hedge positions was driven primarily by the decrease in value of open positions as a result of decreases in coal, natural gas, and ERCOT power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the nine months ended September 30, 2016, the $360 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. The $301 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, as well as the increase in value of open positions as a result of increases in natural gas prices.

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, 2017, and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. 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)	2017			2016
Trading gains/(losses)
Realized	$	18		$	67
Unrealized	(7		)	27
Total trading gains	$	11		$	94

Operations and Maintenance Expense



	Generation				Retail		Renewables		NRG Yield		Corporate		Eliminations			Total
	Gulf Coast		East/West^(a)		Retail		Renewables		NRG Yield		Corporate		Eliminations			Total
	(In millions)
Nine months ended September 30, 2017	$	370	$	284	$	170	$	91	$	143	$	12	$	(32	)	$	1,038
Nine months ended September 30, 2016	419		374		178		93		134		19		(21		)	1,196


(a)	Includes International, BETM and generation eliminations of $3 million in 2017 and $4 million in 2016.

Operations and maintenance expense decreased by $158 million for ~~facilities that were impaired~~the nine months ended September 30, 2017, compared to the same period in ~~2016.~~2016, due to the following:



	(In millions)
Decrease in operation and maintenance expenses due to major maintenance activities and environmental control work at Midwest Generation in 2016	$	(68	)
Decrease in operation and maintenance expenses due to lower expenses at Big Cajun II in 2017	(26		)
Decrease in operation and maintenance expenses due to the deactivation of the Huntley and Dunkirk facilities in 2016	(16		)
Decrease in operation and maintenance expenses due to a reduction in normal maintenance at various gas and coal facilities in Texas	(15		)
Decrease in Retail operation and maintenance expenses due to reduced headcount	(8		)
Decrease in operations and maintenance expenses related to outage work at Arthur Kill in 2016	(6		)
Decrease in operations and maintenance expenses due to a reduction in headcount related to the sale of the Engine Services business	(4		)
Other	(15		)
	$	(158	)

Selling, General and Administrative ~~Expenses~~

Generation Retail Renewables NRG Yield Corporate Total

(In millions)
Three months ended March 31, 2017 $ 82
$ 119
$ 15
$ 5
$ 51
$ 272
Three months ended March 31, 2016 $ 86
$ 111
$ 14
$ 3
$ 38
$ 252

Selling, general and administrative expenses ~~increased~~are comprised of the following:



	Generation		Retail		Renewables		NRG Yield		Corporate		Total
	(In millions)
Nine months ended September 30, 2017	$	155	$	337	$	43	$	16	$	146	$	697
Nine months ended September 30, 2016	195		362		43		10		191		801

Selling, general and administrative expenses decreased by ~~$20~~$104 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2017, compared to the same period in 2016. The ~~increase was~~decrease in year over year expenses is due primarily to ~~$14~~a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.

Reorganization

Reorganization expenses of $18 million were incurred during the third quarter of ~~costs incurred~~2017 related to ~~advisors engaged to assist~~the Transformation Plan announced on July 12, 2017.

Loss on Sale of Assets

During the nine months ended September 30, 2016, the Company sold a majority interest in its ~~strategic review~~EVgo business to Vision Ridge Partners, as described in Note 3, Discontinued Operations, Dispositions and ~~$11~~Acquisitions, of this Form 10-Q, which resulted in a loss on sale of $79 million of costs incurred in connection with advisors and other consultants engaged to assist the Company with GenOn's ability to continue as a going concern. After giving consideration to the increase for these costs, remaining selling, general and administrative expenses decreased quarter over quarter..

Impairment Losses on Investments

~~During~~For the ~~first quarter of~~nine months ended September 30, 2016, the Company recorded other-than-temporary impairment losses of ~~$146~~$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.

Interest Expense

NRG's interest expense decreased by ~~$15~~$26 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2017, compared to the same period in 2016 due to the following:

(In millions)
Decrease due to the repurchases of Senior Notes in 2016 of $55 million, offset by $39 million in Senior Notes issued in 2016 $ (16 )
Decrease in derivative interest expense from changes in fair value of interest rate swaps (11 )
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016 6
Increase due to interest expense related to Midwest Generation financing 4
Other 2
$ (15 )



	(In millions)
Decrease due to the repurchase of Senior Notes in 2016 of $127 million, partly offset by Senior Notes issued in 2016 of $78 million	$	(49	)
Decrease due to termination of swaps related to 2016 Capistrano debt refinancing	(16		)
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016	16
Increase due to the issuance of Carlsbad Energy Project debt and Agua Caliente HoldCo, due 2038 during 2017	10
Increase in derivative interest expense from changes in fair value of interest rate swaps	9
Increase due to the issuance of Yield Operating Senior Notes, due 2026, partially offset by repayment of the Yield Revolving Credit Facility, due 2019 during 2016	8
Other	(4		)
	$	(26	)

Income Tax ~~(Benefit)/~~Expense

For the ~~three~~nine months ended ~~March 31,~~September 30, 2017, NRG recorded an income tax ~~benefit~~expense of $4$5 million on a pre-tax ~~loss~~income of ~~$207~~$125 million. For the same period in 2016, NRG recorded an income tax expense of ~~$21~~$75 million on a pre-tax ~~income~~loss of ~~$68~~$17 million. The effective tax rate was ~~1.9%~~4.0% and ~~30.9%~~(441.2)% for the ~~three~~nine months ended ~~March 31,~~September 30, 2017 and 2016, respectively.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2017,, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance ~~partially offset by~~and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due ~~to the change in the valuation allowance, partially offset by the recording of a deferred liability associated with~~ the amortization of indefinite lived ~~assets.~~assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the ~~three~~nine months ended ~~March 31,~~September 30, 2017 and 2016, 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, ~~as well as~~partially offset by NRG Yield, Inc.'s share of net ~~loss.~~income.

(Loss)/Income from Discontinued Operations, Net of Income Tax (Benefit)/Expense

For the nine months ended September 30, 2017, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense of $802 million.

For the nine months ended September 30, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/expense of $256 million.

Liquidity and Capital Resources

Liquidity Position

As of ~~March 31,~~September 30, 2017 and December 31, 2016, NRG's liquidity, excluding collateral received, was approximately ~~$3.3~~$3.4 billion and $~~3.6~~2.4 billion, respectively, comprised of the following:


(In millions)	March 31, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Cash and cash equivalents:
NRG excluding NRG Yield and GenOn	$	415	$	622
NRG excluding NRG Yield					$	1,044	$	621
NRG Yield and subsidiaries	213		317		179		317
GenOn and subsidiaries	885		1,034
Restricted cash - operating	68		56		124		56
Restricted cash - reserves^(a)	329		390		413		390
Total	1,910		2,419		1,760		1,384
Total credit facility availability	1,364		1,217		1,604		989
Total liquidity, excluding collateral received	$	3,274	$	3,636	$	3,364	$	2,373

^(a)Includes reserves primarily for debt service, performance obligations, and capital ~~expenditures~~expenditures.

For the ~~three~~nine months ended ~~March 31,~~September 30, 2017, total liquidity, excluding collateral funds deposited by counterparties, ~~decreased~~increased by ~~$362 million.~~$1 billion. Changes in cash and cash equivalents balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at ~~March 31,~~September 30, 2017 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

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.~~commitments. 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 $1.5 billion~~On July 12, 2017, NRG announced its Transformation Plan, which is described further in Management's Discussion and Analysis of ~~cash~~Financial Condition and ~~cash equivalents~~Results of ~~the Company as of~~Operations - ~~March 31, 2017~~, $305 million and $82 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, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective 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 ~~March 31, 2017~~, 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.Executive Summary.

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 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 ~~March 31, 2017, 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~~, to this Form 10-Q, $691 million of GenOn's Senior Notes, excluding $4 million of associated premiums, are current within the GenOn consolidated balance sheet as of March 31, 2017 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. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the GenOn 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. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, 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. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern.

During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.

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. As of March 31, 2017, $214 million was available to be used by GenOn under the $500 million revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.

Credit Ratings

On January 10, 2017, GenOn's corporate credit rating was lowered by S&P to CCC- from CCC. The ratings outlook for GenOn, GenOn Americas Generation, GenOn Mid-Atlantic and REMA is negative. In addition, S&P also lowered the issue-level ratings on the GenOn Senior Notes to CCC from CCC+, the GenOn Americas Generation Senior Notes to CCC- from CCC, and the pass-through certificates at REMA and GenOn Mid-Atlantic to CCC+ from B-.

The following table summarizes the Company's credit ratings as of ~~March 31,~~September 30, 2017:



	S&P	Moody's
NRG Energy, Inc.	BB- Stable	Ba3 Stable
7.625% Senior Notes, due 2018	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~~	~~Caa3~~
~~GenOn 9.500% Senior Notes, due 2018~~	~~CCC~~	~~Caa3~~
~~GenOn 9.875% Senior Notes, due 2020~~	~~CCC~~	~~Caa3~~
~~GenOn Americas Generation 8.500% Senior Notes, due 2021~~	~~CCC-~~	~~Caa3~~
~~GenOn Americas Generation 9.125% Senior Notes, due 2031~~	~~CCC-~~	~~Caa3~~
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

On October 6, 2017, Moody's upgraded the NRG rating outlook to positive from stable and affirmed NRG's Ba3 Corporate Family Rating.

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 2016 Form 10-K, the Company's financing arrangements consist mainly of the 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.

Carlsbad Project Financing

Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The Carlsbad Financing Agreement also includes a letters of credit facility not to exceed aggregate amount of $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million.

ROFO Agreement Expansion and Offer

On February 24, 2017, the Company amended and restated the ROFO Agreement to expand the ROFO assets pipeline with the addition of 234 net MW of utility-scale solar projects. These assets include Buckthorn Solar, a 154 net MW facility located in Texas, and the Hawaii Solar projects, which have a combined capacity of 80 net MW.

On October 17, 2017, the Company offered NRG Yield, Inc. the opportunity to purchase 100% of its ownership interest in Buckthorn Solar pursuant to the ROFO Agreement.

Sale of Assets to NRG Yield, Inc.

On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in working capital adjustments.

On August 1, 2017, NRG closed on its sale of the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to NRG Yield, Inc. for total cash consideration of $44 million. The transaction also includes potential additional payments to NRG dependent on actual energy prices for merchant periods beginning in 2027.

On May 23, 2017, NRG offered NRG Yield, Inc. the opportunity to form a new distributed solar investment partnership enabling up to $50 million in investment by NRG Yield, Inc. In addition, on July 31, 2017, NRG offered NRG Yield, Inc. equity interests in a 38 MW portfolio of distributed and small utility-scale solar assets primarily comprised of assets from NRG's Solar Power Partners, or SPP, funds in addition to other projects developed since the acquisition of SPP. These equity interests are not part of the ROFO Agreement. Both the distributed solar investment partnership and the distributed and small utility-scale solar acquisitions are subject to negotiation and approval by NRG Yield, Inc.'s independent directors. As of September 30, 2017, NRG Yield, Inc has invested $41 million in distributed solar investment partnerships with NRG.

On March 27, 2017, the Company sold (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity which have reached commercial operations to NRG Yield, Inc. NRG Yield Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt of approximately $328 million.

2023 Term Loan Facility

On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%, the LIBOR floor remains 0.75%. As a result of the repricing, the Company expects interest savings of approximately $9 million in 2017 and approximately $60 million in interest savings over the life of the loan.

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.~~exposure as the lien counterparty’s exposure to NRG is positively correlated to the value of the specified generation assets. 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.~~These volumetric limits, exclude Midwest Generation's coal capacity. 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 ~~March 31,~~September 30, 2017, all hedges under the first liens were out-of-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 ~~March 31,~~September 30, 2017:


Equivalent Net Sales Secured by First Lien Structure ^(a)	2017		2018		2019		2020		2021		2017		2018		2019		2020		2021
In MW	2,150		1,158		—		—		—		1,458		1,093		—		—		—
As a percentage of total net coal and nuclear capacity ^(b)	40	%	21	%	—	%	—	%	—	%	27	%	20	%	—	%	—	%	—	%


(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,~~acquisition, assets in NRG Yield, Inc. and NRG's assets that have project level financing.

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 acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders.

Senior Note Redemptions

On October 16, 2017, the Company redeemed $398 million of its 7.625% Senior Notes due 2018 and $206 million of its 7.875% Senior Notes due 2021 for $630 million, which included $14 million in accrued interest. As a result of the senior note redemptions a $12 million loss on debt extinguishment will be recorded in the fourth quarter of 2017. In addition, the Company expects to save approximately $47 million in annualized interest.

Restructuring Support Agreement

As described in Note 3, Discontinued Operations, Dispositions and Acquisitions, NRG, the GenOn Entities and certain holders of the GenOn and GenOn Americas Generation Senior Notes entered into a Restructuring Support Agreement, that provides for a restructuring and recapitalization of GenOn through a prearranged plan of reorganization. Certain principal terms of the Restructuring Support Agreement include that NRG will provide settlement consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2017, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, to be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit facility was terminated, as GenOn has obtained a separate letter of credit facility with a third party financial institution. In addition, NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of September 30, 2017 was approximately $106 million. See Note 1, Basis of Presentation, for further discussion regarding the October 30, 2017 proposed changes to the Restructuring Support Agreement, which includes the retention of the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million, recorded as a liability as of September 30, 2017.

Revolving Credit Facility

As of September 30, 2017, there were no cash borrowings outstanding on the revolver.

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 ~~March 31,~~September 30, 2017, commercial operations had total cash collateral outstanding of ~~$277~~$274 million, and ~~$861~~$606 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of ~~March 31,~~September 30, 2017, total collateral held from counterparties was $3$31 million in cash and ~~$16~~$17 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.

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments for the ~~three~~nine months ended ~~March 31,~~September 30, 2017, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2017.


	Maintenance		Environmental		Growth Investments			Total			Maintenance		Environmental		Growth Investments			Total
	(In millions)										(In millions)
Generation
Gulf Coast	$	40	$	1	$	1		$	42		$	73	$	1	$	3		$	77
East	19		24		15			58
West	—		—		81			81
Other	1		—		—			1
East/West											17		24		240			281
Retail	6		—		4			10			22		—		33			55
Renewables	1		—		67			68			3		—		309			312
NRG Yield	4		—		—			4			21		—		2			23
Corporate^(b)	1		—		3			4
Total cash capital expenditures for the three months ended March 31, 2017	72		25		171			268
Corporate											11		—		1			12
Total cash capital expenditures for the nine months ended September 30, 2017											147		25		588			760
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(51		)	(51		)	—		—		(815		)	(815		)
Other investments ^(a)	—		—		33			33			—		—		95			95
Total capital expenditures and investments, net of financings	72		25		153			250			147		25		(132		)	40

Estimated capital expenditures for the remainder of 2017	221		25		625			871			76		10		430			516
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(611		)	(611		)	—		—		(211		)	(211		)
Other investments ^(a)	—		—		26			26
NRG estimated capital expenditures for the remainder of 2017, net of financings	$	221	$	25	$	40		$	286		$	76	$	10	$	219		$	305


(a)	Other investments include restricted cash activity.

Environmental capital expenditures — For the ~~three~~nine months ended ~~March 31,~~September 30, 2017, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy ~~CPS as well as controls to satisfy MATS at the Avon Lake Facility.~~CPS.

Growth Investments capital expenditures — For the ~~three~~nine months ended ~~March 31,~~September 30, 2017, the Company's growth investment capital expenditures included ~~$88~~$245 million for solar projects, $241 million for repowering projects, ~~$55 million for solar projects, $12~~$65 million for wind projects ~~$9 million for fuel conversions~~ and $7$37 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2017 through 2021 required to comply with environmental laws will be approximately ~~$132~~$60 million, which includes ~~$61 million for GenOn and $38~~$16 million for Midwest Generation. ~~These costs are~~The increase from last quarter is driven primarily ~~associated with~~by the ~~cost of complying with the ELG requirements as they exist today. As discussed in Item 1 - Note 16,~~ ~~Environmental Matters, the ELG rule has been challenged. The Company expects to reduce its estimate~~addition of the ~~environmental capital expenditures that would be required to comply with permits issued that incorporate~~anticipated costs of adding NOx control equipment at certain of the ~~revised ELG guidelines.~~Company's units in Connecticut.

Dividends

The following table lists the dividends paid during the ~~three~~nine months ended ~~March 31,~~September 30, 2017:

First Quarter 2017
Dividends per Common Share $ 0.030



	Third Quarter 2017		Second Quarter 2017		First Quarter 2017
Dividends per Common Share	$	0.030	$	0.030	$	0.030

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.

~~GenOn Mid-Atlantic Long-Term Deposits~~

On January 27, 2017, GenOn Mid-Atlantic entered into an agreement with Natixis under which Natixis will procure payment and credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. GenOn Mid-Atlantic made a payment of $130 million plus fees of $1 million as consideration for Natixis applying for the issuance of, and obtaining, letters of credit from Natixis, New York Branch, the LC Provider, to support the lease payments. Natixis is solely responsible for (i) obtaining letters of credit from the LC Provider, (ii) causing the letters of credit to be issued to the lessors to support the lease payments on behalf of GenOn Mid-Atlantic, (iii) making lease payments and (iv) satisfying any reimbursement obligations payable to the LC Provider.

On February 24, 2017, GenOn Mid-Atlantic received a series of notices from certain of the owner lessors under its operating leases of the Morgantown coal generation unit alleging default, or Notices. The Notices allege the existence of lease events of default as a result of, among other items, the purported failure by GenOn Mid-Atlantic to comply with a covenant requiring the maintenance of qualifying credit support. The Notices instructed the relevant trustees to draw on letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn, supporting the GenOn Mid-Atlantic operating leases that were set to expire on February 28, 2017. The offset was recorded to other non-current assets under the related operating leases pending resolution of the matter which is further described below. On February 28, 2017, the trustees drew on the letters of credit under NRG's revolving credit facility, which resulted in borrowings of $125 million. Upon notification, GenOn became obligated under the secured intercompany revolving credit agreement between NRG and GenOn. GenOn requested GenOn Mid-Atlantic repay the related amount borrowed under the secured intercompany revolving credit agreement. GenOn Mid-Atlantic is unaware of whether any further action will be taken by the owner lessors or any other person in connection with the Notices. GenOn Mid-Atlantic disagrees with the owner lessors as to the existence of any lease events of default and/or any breaches by GenOn Mid-Atlantic of any terms and conditions of the operating leases and believes that the declaration of a lease event of default, the instruction to draw on the letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn and the draws thereon constituted a violation by the owner lessors and the relevant trustees of the terms and conditions of the GenOn Mid-Atlantic operating leases. GenOn Mid-Atlantic intends to vigorously pursue its rights and remedies in connection with these actions. On March 7, 2017, GenOn Mid-Atlantic filed a complaint in the Supreme Court for the State of New York against the owner lessors of the Morgantown and Dickerson facilities and U.S. Bank National Association in its capacity as the indenture trustee. The complaint seeks, ~~inter alia~~, a declaratory judgment that no lease events of default exist and asserts counts for breach of contract, conversion, tortious interference, breach of the implied covenant of good faith and fair dealing, unjust enrichment, constructive trust, and injunctive relief. The defendants in this action have not yet responded to the complaint and have until June 5, 2017 to do so. The court has set an initial conference hearing for June 12, 2017.

Fuel Repowerings

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)^(b)		Project Type		Fuel Type		Targeted COD
Repowerings
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT	527		Growth		Natural Gas		Q4 2018
Puente (formerly Mandalay) Units 1 and 2^(a)	262		Growth		Natural Gas		Q2 2020
~~Bacliff (formerly Cielo Lindo/PH Robinson) Peakers 1-6~~	~~360~~		~~Growth~~		~~Natural Gas~~		~~Q2 2017~~
Total Fuel Repowerings	~~1,149~~789

(a) ~~Projects are subject~~See Regulatory Matters in the Management's Discussion and Analysis to ~~applicable regulatory approvals~~this Form 10-Q for recent developments in the permitting process that may impact the viability of the Puente project.

(b On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and ~~permits.~~Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated damages.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative ~~three~~nine month periods:


	Three months ended March 31,									Nine months ended September 30,
	2017			2016			Change			2017			2016			Change
	(In millions)									(In millions)
Net cash used by operating activities	$	(68	)	$	554		$	(622	)	$	806		$	1,741		$	(935	)
Net cash used by investing activities	(232		)	(143		)	(89		)	(765		)	(255		)	(510		)
Net cash used by financing activities	(153		)	(264		)	111
Net cash provided by financing activities										59			(587		)	646

Net Cash Used By Operating Activities

Changes to net cash used by operating activities were driven by:


	(In millions)			(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	$	(230	)	$	(364	)
Decrease in operating income adjusted for non-cash items	(215		)	(216		)
Increase due to lower generation in the first quarter of 2017, combined with earlier inventory purchases in the fourth quarter of 2015 for anticipated 2016 generation requirements	(119		)
Increase in accounts receivable due to lower overall revenue rates and receipt of Cottonwood insurance proceeds	(59		)
Decrease in other assets and liabilities				(127		)
Cash used by discontinued operations				(105		)
Decrease in accounts payable due to lower expenses and the timing of payments in 2017 compared to 2016.				(68		)
Increase in inventory due to lower generation in 2017, combined with earlier inventory purchases in the fourth quarter of 2015 for anticipated 2016 generation requirements				(64		)
Other	1			(35		)
Decrease in accounts receivable due to the timing of cash receipts in 2017 compared to 2016				44
	$	(622	)	$	(935	)

Net Cash Used By Investing Activities

Changes to net cash used by investing activities were driven by:

(In millions)
Decrease in proceeds from the sale of assets primarily related to the sale of the Seward and Shelby generating stations in 2016 $ (106 )
Net decrease in nuclear decommissioning trust fund activity (27 )
Increase in investments in unconsolidated affiliates, primarily related to the 2016 utility-scale solar and wind asset acquisitions (8 )
Decrease in restricted cash primarily due to decreases in the Alta Wind, CVSR, Agua Caliente and SPP Fund accounts of $49 million, offset by an increase in Solar Partners LLC of $32 million 22
Increase in insurance proceeds received in 2017, related to the Cottonwood generation station outage in 2016 18
Decrease in capital expenditures for environmental and maintenance projects of $76 million primarily for Powerton and Joliet capitalized in 2016, offset by an increase in growth projects of $96 million primarily for repowering and solar projects 11
Other 1
$ (89 )



	(In millions)
Cash used by discontinued operations	$	(379	)
Decrease in maintenance and environmental capital expenditures, offset by an increase in growth capital expenditures	(101		)
Proceeds from sale of assets in 2016 compared to 2017	(48		)
Increase in cash paid for acquisitions in 2017 compared to 2016	(18		)
Other	(7		)
Net increase in emissions allowances activity	43
	$	(510	)

Net Cash ~~Used~~Provided By Financing Activities

Changes to net cash ~~used~~provided by financing activities were driven by:

(In millions)
Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038 Senior Notes as well as reduced payments due to repurchases of Senior Notes in 2016 $ 270
Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016 39
Payment for credit support in long-term deposits (130 )
Decrease in financing element related to acquired derivatives (38 )
Increase in debt issuance cost primarily due to repricing of the 2023 Senior Notes and the issuance of the Agua Caliente 1 & 2, 2038 Senior Notes (15 )
Decrease in cash contributions from non-controlling interest in 2017 (15 )
$ 111



	(In millions)
Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038 Senior Notes and the Carlsbad Project Financing as well as reduced payments due to repurchases of Senior Notes in 2016	$	538
Increase due to purchase of preferred stock in 2016	226
Increase in cash contributions, net of distributions from non-controlling interest in 2017	192
Decrease in debt extinguishment cost	98
Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016	38
Decrease in deferred debt issuance cost	27
Decrease in financing element related to acquired derivatives	(5		)
Payment for affiliate receivable	(125		)
Cash used by discontinued operations	(343		)
	$	646

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

For the ~~three~~nine months ended ~~March 31,~~September 30, 2017, the Company had a total domestic pre-tax book ~~loss~~income of ~~$208~~$112 million and foreign pre-tax book income of $1$13 million. As of December 31, 2016, the Company ~~has~~had cumulative domestic Federal NOL carryforwards of $3.4 billion, of which $1.2 billion is from GenOn Energy, Inc. and subsidiaries which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.9 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $196 million, which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $7.8 billion worthless stock deduction for tax purposes. The NOL balances of $1.2 billion will remain with the GenOn group of companies upon emergence from bankruptcy.

In addition to these amounts, the Company has ~~$35~~$36 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 ~~$35~~$25 million in 2017.

The Company has recorded a non-current tax liability of ~~$38~~$40 million until final resolution with the related taxing authority. The ~~$38~~$40 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 prior to 2010. 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 ~~March 31,~~September 30, 2017, 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 ~~$628~~$616 million as of ~~March 31,~~September 30, 2017. 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 2016 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 2016 Form 10-K. See also Note 8, Debt and Capital Leases, and Note 1415, 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 three and nine months ended ~~March 31,~~September 30, 2017.

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 2016 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 ~~March 31,~~September 30, 2017, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at ~~March 31,~~September 30, 2017.


Derivative Activity Losses	(In millions)
Derivative Activity (Losses)/Gains				(In millions)
Fair Value of Contracts as of December 31, 2016	$	(127	)	$	(128	)
Contracts realized or otherwise settled during the period	(16		)	21
Changes in fair value	(11		)	(41		)
Fair Value of Contracts as of March 31, 2017	$	(154	)
Fair Value of Contracts as of September 30, 2017				$	(148	)


	Fair Value of Contracts as of March 31, 2017															Fair Value of Contracts as of September 30, 2017
	Maturity															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
Fair value hierarchy (Losses)/Gains																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)															(In millions)
Level 1	$	9		$	(58	)	$	(13	)	$	—		$	(62	)	$	(34	)	$	(30	)	$	(5	)	$	—		$	(69	)
Level 2	(39		)	6			(2		)	1			(34		)	11			(28		)	(14		)	—			(31		)
Level 3	(35		)	(11		)	(5		)	(7		)	(58		)	(24		)	(11		)	(5		)	(8		)	(48		)
Total	$	(65	)	$	(63	)	$	(20	)	$	(6	)	$	(154	)	$	(47	)	$	(69	)	$	(24	)	$	(8	)	$	(148	)

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 ~~March 31,~~September 30, 2017,, NRG's net derivative liability was ~~$154~~$148 million, a decrease to total fair value of ~~$27~~$20 million as compared to December 31, ~~2016~~.2016. This decrease was driven by losses in fair value, largely offset by the roll-off of trades that settled during the ~~period and losses in fair value.~~period.

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 an increase of approximately ~~$66~~$39 million in the net value of derivatives as of ~~March 31, 2017~~.September 30, 2017. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately ~~$82~~$62 million in the net value of derivatives as of ~~March 31, 2017~~.September 30, 2017.

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 GAAP. The preparation of these financial statements and related disclosures in compliance with 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 and investments, 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~~Company’s annual budget is utilized to determine the cash flows associated with the Company’s long-lived assets, which incorporates various assumptions, including the Company’s long-term view of natural gas prices ~~continue~~and its impact on merchant power prices and fuel costs. The Company’s annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is reasonably possible that the updated long term cash flows will not support the carrying value of certain assets, and the Company will be required to ~~decrease, this~~test such assets for impairment. This could also 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~~balances. This decrease in ~~natural gas~~power prices could also 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,~~During the preparation of the budget, the Company noted that management’s view of long term merchant power prices has decreased, and accordingly, it is reasonably possible that certain of the Company's goodwill and/or long-lived assets will be ~~impaired.~~significantly impaired during the fourth quarter of 2017.

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 2016 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 three and nine months ~~ending~~ended ~~March 31,~~September 30, 2017 and 2016:


(In millions)	2017		2016		2017		2016
VaR as of March 31,	$	60	$	59
Three months ended March 31,
VaR as of September 30,					$	40	$	40
Three months ended September 30,
Average	$	52	$	54	$	30	$	59
Maximum	60		60		40		72
Minimum	41		44		25		40
Nine months ended September 30,
Average					$	27	$	58
Maximum					40		72
Minimum					20		40

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 ~~March 31,~~September 30, 2017, for the entire term of these instruments entered into for both asset management and trading was ~~$19~~$17 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 2016 Form 10-K for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on ~~March 31,~~September 30, 2017, the Company would have owed the counterparties $3043 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 ~~March 31,~~September 30, 2017, a 1% change in variable interest rates would result in a $~~12.8~~13.8 million change in interest expense on a rolling twelve month basis.

As of ~~March 31,~~September 30, 2017, the fair value and related carrying value of the Company's debt was ~~$18.7~~$17.4 billion and ~~$19.5~~$17.1 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 ~~$1.5 billion~~.$984 million.

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 $~~220~~164 million as of ~~March 31,~~September 30, 2017, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $~~176~~149 million as of ~~March 31,~~September 30, 2017. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of ~~March 31,~~September 30, 2017.

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.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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 ~~first~~third quarter of 2017 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through ~~March 31,~~September 30, 2017, see Note 1415, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, Risk Factors Related to NRG Energy, Inc., in the Company's 2016 Form ~~10-K.~~10-K, and Part II, Item 1A of the Company's Form 10-Q for the quarter ended June 30, 2017. There have been no material changes in the Company's risk factors since those reported in its 2016 Form 10‑K.K and its Form 10-Q for the quarter ended June 30, 2017.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

~~None.~~See Note 3, Discontinued Operations, Dispositions and Acquisitions, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a description of events of default by GenOn and GenOn Americas Generation under the GenOn Senior Notes and the GenOn Americas Generation Senior Notes.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
10.1*10.1	~~NRG Energy, Inc.~~ Amended and Restated ~~Long-Term Incentive Plan.~~Backstop Commitment Letter, dated as of October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the guarantors party thereto and backstop parties thereto.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on ~~April 28,~~October 6, 2017.
10.2*10.2	First Amendment, dated as of October 2, 2017, to the Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, NRG Energy, Inc. ~~Amended~~ and ~~Restated Employee Stock Purchase Plan.~~the consenting noteholders party thereto.	Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on ~~April 28,~~October 6, 2017.
10.3	Consent Agreement, dated as of October 30, 2017, by and among GenOn Energy, Inc, GenOn Americas Generation LLC, and certain of their directly and indirectly owned subsidiaries listed on the signature pages thereto, and the Required Consenting Noteholders.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 1, 2017.
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.

* Exhibit relates to compensation arrangements.

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: ~~May~~November 2, 2017	Chief Accounting Officer (Principal Accounting Officer)

85107



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	910
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	910
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	5265
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	80102
ITEM 4 — CONTROLS AND PROCEDURES	82104
PART II — OTHER INFORMATION	83105
ITEM 1 — LEGAL PROCEEDINGS	83105
ITEM 1A — RISK FACTORS	83105
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	83105
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	83105
ITEM 4 — MINE SAFETY DISCLOSURES	83105
ITEM 5 — OTHER INFORMATION	83105
ITEM 6 — EXHIBITS	84106
SIGNATURES	85107



	Generation^(a)			Retail ^(a)			Renewables^(a)(b)			NRG Yield			Corporate^(a)			Eliminations			Total
Three months ended March 31, 2017	(In millions)
Operating revenues^(a)	$	1,343		$	1,335		$	98		$	218		$	8		$	(243	)	$	2,759
Depreciation and amortization	138			28			49			75			10			—			300
Equity in (losses)/earnings of unconsolidated affiliates	(13		)	—			(1		)	19			3			(3		)	5
Gain on sale of assets	2			—			—			—			—			—			2
Income/(loss) before income taxes	67			(30		)	(37		)	(2		)	(203		)	(2		)	(207		)
Net Income/(Loss)	67			(33		)	(31		)	(1		)	(203		)	(2		)	(203		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	67		$	(32	)	$	(3	)	$	13		$	(203	)	$	(5	)	$	(163	)
Total assets as of March 31, 2017	$	12,962		$	2,150		$	5,123		$	8,580		$	14,621		$	(14,016	)	$	29,420



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	205	$	1	$	8		$	—	$	29	$	—	$	243
(b) Includes loss on debt extinguishment	$	—	$	—	$	(2	)	$	—	$	—	$	—	$	(2	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	118	$	3	$	6	$	4	$	66	$	—	$	197
(b) Includes gain on debt extinguishment	$	—	$	—	$	—	$	—	$	11	$	—	$	11



(In millions)	Gross Margin increase/(decrease)			Economic Gross Margin increase/(decrease)
Gulf Coast region	$	35		$	(112	)
East region	(249		)	(216		)
West region	(53		)	(66		)
Other	(35		)	(35		)
	$	(302	)	$	(429	)



	(In millions)
Lower gross margin due to lower average realized prices primarily in Texas due to lower hedged power prices	$	(101	)
Lower gross margin primarily due to contract expirations and lower demand	(15		)
Lower gross margin due to a 66% decrease in ISO capacity prices and a 14% decrease in capacity volume	(14		)
Lower gross margin due to increased supply costs on load contracts	(8		)
Lower gross margin resulting from an 8% decrease in nuclear generation driven by the timing of planned outages	(7		)
Higher gross margin primarily due to higher coal generation mainly in Texas which was driven by the timing of planned outages	31
Other	2
Decrease in economic gross margin	$	(112	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	147
Increase in gross margin	$	35



	(In millions)
Lower gross margin due to a 43% decrease in New York and New England hedged capacity prices and a 32% decrease in PJM cleared auction capacity prices	$	(77	)
Lower gross margin due to a 30% decrease in generation as a result of deactivating the Huntley and Dunkirk facilities in 2016, the sale of the Seward, Aurora and Shelby generating stations in 2016, as well as milder winter weather conditions in 2017	(55		)
Lower gross margin due to a 32% increase in the price of natural gas and transportation costs due to less favorable short-term natural gas contract terms, as well as a 2% decrease in average realized energy prices	(35		)
Lower gross margin due to higher supply costs for servicing certain load contracts	(22		)
Lower gross margin due to lower contracted volumes and prices in New York	(17		)
Changes in commercial optimization activities	(17		)
Higher gross margin due to fewer outage hours primarily in PJM, due to unit conversions and deactivations	12
Other	(5		)
Decrease in economic gross margin	$	(216	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(33		)
Decrease in gross margin	$	(249	)



	(In millions)
Lower gross margin due to the gain on sale of excess emission credits in 2016	$	(47	)
Lower gross margin due to a 45% decrease in capacity volume primarily due to the retirement of the Pittsburg generating station, partially offset by a 14% increase in capacity prices	(16		)
Other	(3		)
Decrease in economic gross margin	$	(66	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	10
Increase in contract and emission credit amortization	3
Decrease in gross margin	$	(53	)



	(In millions)
Weather driven gross margin is lower by $12 million due to a reduction in load of 308,000 MWhs and $7 million in lower margin due to the unfavorable impacts of selling back excess supply in 2017 as compared to 2016	$	(19	)
Lower gross margin due to lower rates to customers of $54 million, or approximately $6 per MWh, partially offset by lower supply costs of $45 million, or approximately $5 per MWh driven primarily by a decrease in power prices at the time of procurement	(9		)
Higher gross margin due to higher volumes driven by higher average customer usage and mix and an increase in customer count	19
Decrease in economic gross margin	$	(9	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(170		)
Increase in contract and emission credit amortization	2
Decrease in gross margin	$	(177	)



	(In millions)
Decrease due to the repurchases of Senior Notes in 2016 of $55 million, offset by $39 million in Senior Notes issued in 2016	$	(16	)
Decrease in derivative interest expense from changes in fair value of interest rate swaps	(11		)
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016	6
Increase due to interest expense related to Midwest Generation financing	4
Other	2
	$	(15	)



	(In millions)
Decrease in proceeds from the sale of assets primarily related to the sale of the Seward and Shelby generating stations in 2016	$	(106	)
Net decrease in nuclear decommissioning trust fund activity	(27		)
Increase in investments in unconsolidated affiliates, primarily related to the 2016 utility-scale solar and wind asset acquisitions	(8		)
Decrease in restricted cash primarily due to decreases in the Alta Wind, CVSR, Agua Caliente and SPP Fund accounts of $49 million, offset by an increase in Solar Partners LLC of $32 million	22
Increase in insurance proceeds received in 2017, related to the Cottonwood generation station outage in 2016	18
Decrease in capital expenditures for environmental and maintenance projects of $76 million primarily for Powerton and Joliet capitalized in 2016, offset by an increase in growth projects of $96 million primarily for repowering and solar projects	11
Other	1
	$	(89	)