NRG ENERGY, INC. - Quarter Report: 2017 June (Form 10-Q)

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: June 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 July 31, 2017, there were 316,460,692 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	9
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	9
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	62
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	98
ITEM 4 — CONTROLS AND PROCEDURES	100
PART II — OTHER INFORMATION	101
ITEM 1 — LEGAL PROCEEDINGS	101
ITEM 1A — RISK FACTORS	101
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	102
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	102
ITEM 4 — MINE SAFETY DISCLOSURES	102
ITEM 5 — OTHER INFORMATION	102
ITEM 6 — EXHIBITS	103
SIGNATURES	104

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:


•	NRG's ability to achieve the expected benefits of its 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 achieve anticipated benefits therefrom;


•	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;


•	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;


•	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
2023 Term Loan Facility		The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit Facility
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 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
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
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 Entities		GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation. that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the 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 $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% 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, 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
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
Senior Notes		As of June 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
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
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 June 30,						Six months ended June 30,
(In millions, except for per share amounts)	2017			2016			2017			2016
Operating Revenues
Total operating revenues	$	2,701		$	2,248		$	5,083		$	4,907
Operating Costs and Expenses
Cost of operations	1,837			1,443			3,696			3,271
Depreciation and amortization	260			262			517			528
Impairment losses	63			56			63			56
Selling, general and administrative	223			266			482			520
Acquisition-related transaction and integration costs	1			5			2			6
Development activity expenses	18			18			35			44
Total operating costs and expenses	2,402			2,050			4,795			4,425
Other income - affiliate	42			48			90			96
Gain/(loss) on sale of assets	2			(83		)	4			(83		)
Operating Income	343			163			382			495
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(3		)	4			2			(3		)
Gain/(impairment loss) on investment	—			7			—			(139		)
Other income, net	10			5			18			22
Loss on debt extinguishment, net	—			(80		)	(2		)	(69		)
Interest expense	(247		)	(237		)	(471		)	(479		)
Total other expense	(240		)	(301		)	(453		)	(668		)
Income/(Loss) from Continuing Operations Before Income Taxes	103			(138		)	(71		)	(173		)
Income tax expense/(benefit)	4			25			(1		)	47
Income/(Loss) from Continuing Operations	99			(163		)	(70		)	(220		)
Loss from discontinued operations, net of income tax	(741		)	(113		)	(775		)	(9		)
Net Loss	(642		)	(276		)	(845		)	(229		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	(16		)	(5		)	(55		)	(40		)
Net Loss Attributable to NRG Energy, Inc.	(626		)	(271		)	(790		)	(189		)
Dividends for preferred shares	—			—			—			5
Gain on redemption of preferred shares	—			(78		)	—			(78		)
Loss Available for Common Stockholders	$	(626	)	$	(193	)	$	(790	)	$	(116	)
Loss per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted	316			315			316			315
Income/(loss) from continuing operations per weighted average common share — basic and diluted	$	0.36		$	(0.25	)	$	(0.05	)	$	(0.34	)
Loss from discontinued operations per weighted average common share — basic and diluted	$	(2.34	)	$	(0.36	)	$	(2.45	)	$	(0.03	)
Loss per Weighted Average Common Share — Basic and Diluted	$	(1.98	)	$	(0.61	)	$	(2.50	)	$	(0.37	)
Dividends Per Common Share	$	0.03		$	0.03		$	0.06		$	0.18

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)



	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(In millions)
Net loss	$	(642	)	$	(276	)	$	(845	)	$	(229	)
Other comprehensive income/(loss), net of tax
Unrealized loss on derivatives, net of income tax expense of $0, $1, $1, and $2	(5		)	(3		)	(1		)	(35		)
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0	1			(3		)	8			3
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0	1			(2		)	1			1
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0	27			—			27			1
Other comprehensive income/(loss)	24			(8		)	35			(30		)
Comprehensive loss	(618		)	(284		)	(810		)	(259		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests	(17		)	(16		)	(56		)	(68		)
Comprehensive loss attributable to NRG Energy, Inc.	(601		)	(268		)	(754		)	(191		)
Dividends for preferred shares	—			—			—			5
Gain on redemption of preferred shares	—			(78		)	—			(78		)
Comprehensive loss available for common stockholders	$	(601	)	$	(190	)	$	(754	)	$	(118	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2017			December 31, 2016
(In millions, except shares)
ASSETS
Current Assets
Cash and cash equivalents	$	752		$	938
Funds deposited by counterparties	19			2
Restricted cash	469			446
Accounts receivable, net	1,162			1,058
Inventory	713			721
Derivative instruments	644			1,067
Cash collateral paid in support of energy risk management activities	277			150
Current assets - held for sale	33			9
Prepayments and other current assets	400			404
Current assets - discontinued operations	—			1,919
Total current assets	4,469			6,714
Property, plant and equipment, net	15,302			15,369
Other Assets
Equity investments in affiliates	1,127			1,120
Notes receivable, less current portion	9			16
Goodwill	662			662
Intangible assets, net	1,893			1,973
Nuclear decommissioning trust fund	637			610
Derivative instruments	226			181
Deferred income taxes	211			225
Non-current assets held-for-sale	10			10
Other non-current assets	659			841
Non-current assets - discontinued operations	—			2,961
Total other assets	5,434			8,599
Total Assets	$	25,205		$	30,682
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,042		$	516
Accounts payable	757			782
Accounts payable - affiliate	17			31
Derivative instruments	711			1,092
Cash collateral received in support of energy risk management activities	19			81
Accrued expenses and other current liabilities	810			990
Accrued expenses and other current liabilities - affiliate	164			—
Current liabilities - discontinued operations	—			1,210
Total current liabilities	3,520			4,702
Other Liabilities
Long-term debt and capital leases	15,842			15,957
Nuclear decommissioning reserve	262			287
Nuclear decommissioning trust liability	367			339
Deferred income taxes	20			20
Derivative instruments	293			284
Out-of-market contracts, net	219			230
Non-current liabilities held-for-sale	13			11
Other non-current liabilities	1,135			1,151
Non-current liabilities - discontinued operations	—			3,209
Total non-current liabilities	18,151			21,488
Total Liabilities	21,671			26,190
Redeemable noncontrolling interest in subsidiaries	51			46
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,383			8,358
Retained deficit	(4,874		)	(3,787		)
Less treasury stock, at cost — 101,858,284 and 102,140,814 shares, respectively	(2,392		)	(2,399		)
Accumulated other comprehensive loss	(100		)	(135		)
Noncontrolling interest	2,462			2,405
Total Stockholders’ Equity	3,483			4,446
Total Liabilities and Stockholders’ Equity	$	25,205		$	30,682

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six months ended June 30,
(In millions)	2017			2016
Cash Flows from Operating Activities
Net loss	$	(845	)	$	(229	)
Loss from discontinued operations, net of income tax	(775		)	(9		)
Loss from continuing operations	(70		)	(220		)
Adjustments to reconcile net loss to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	26			32
Depreciation and amortization	517			528
Provision for bad debts	18			20
Amortization of nuclear fuel	24			26
Amortization of financing costs and debt discount/premiums	29			29
Adjustment for debt extinguishment	—			14
Amortization of intangibles and out-of-market contracts	51			82
Amortization of unearned equity compensation	16			16
Impairment losses	63			195
Changes in deferred income taxes and liability for uncertain tax benefits	8			1
Changes in nuclear decommissioning trust liability	2			13
Changes in derivative instruments	7			(7		)
Changes in collateral posted in support of risk management activities	(189		)	323
Proceeds from sale of emission allowances	11			17
Loss on sale of assets	(22		)	83
Changes in other working capital	(379		)	(272		)
Cash provided by continuing operations	112			880
Cash (used) by discontinued operations	(38		)	(69		)
Net Cash Provided by Operating Activities	74			811
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(16		)	(17		)
Capital expenditures	(542		)	(442		)
Increase in notes receivable	8			(3		)
Purchases of emission allowances	(30		)	(27		)
Proceeds from sale of emission allowances	59			25
Investments in nuclear decommissioning trust fund securities	(279		)	(280		)
Proceeds from the sale of nuclear decommissioning trust fund securities	277			267
Proceeds from renewable energy grants and state rebates	8			10
Proceeds from sale of assets, net of cash disposed of	35			25
Investments in unconsolidated affiliates	(30		)	1
Other	18			31
Cash used by continuing operations	(492		)	(410		)
Cash used by discontinued operations	(53		)	(60		)
Net Cash Used by Investing Activities	(545		)	(470		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(19		)	(57		)
Payment for preferred shares	—			(226		)
Net receipts from settlement of acquired derivatives that include financing elements	2			4
Proceeds from issuance of long-term debt	946			3,223
Payments for short and long-term debt	(530		)	(3,505		)
Receivable from affiliate	(125		)	—
Distributions to, net of contributions from, noncontrolling interest in subsidiaries	14			(21		)
Payment of debt issuance costs	(36		)	(35		)
Other - contingent consideration	(10		)	(10		)
Cash provided/(used) by continuing operations	242			(627		)
Cash used by discontinued operations	(224		)	97
Net Cash provided/(used) by Financing Activities	18			(530		)
Effect of exchange rate changes on cash and cash equivalents	(8		)	(3		)
Change in Cash from discontinued operations	(315		)	(32		)
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(146		)	(160		)
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	$	1,240		$	1,162

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 a diverse competitive electric generation portfolio and leading retail electricity platform. NRG 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 needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company owns and operates approximately 31,000 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 June 30, 2017, and the results of operations, comprehensive income/(loss) and cash flows for the three and six months ended June 30, 2017 and 2016.

GenOn Chapter 11 Cases

On June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries, or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S. Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries, did not file for relief under Chapter 11.

As a result of the 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 has 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 reflect GenOn as a discontinued operation. In connection with the disposal, NRG has recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3, Discontinued Operations and Dispositions, for more information.

Prior to the GenOn Entities' filing the Chapter 11 Cases, 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. There is 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 and Dispositions.

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 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 $2.5-$4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the monetization of 50-100% of its interest in NRG Yield, Inc. and its renewables platform.

Capital structure and 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 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 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 (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:



	June 30, 2017		December 31, 2016
	(In millions)
Accounts receivable allowance for doubtful accounts	$	39	$	29
Property, plant and equipment accumulated depreciation	6,180		5,711
Intangible assets accumulated amortization	1,698		1,687
Out-of-market contracts accumulated amortization	346		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.



	June 30, 2017		December 31, 2016		June 30, 2016		December 31, 2015
	(In millions)
Cash and cash equivalents	$	752	$	938	$	748	$	853
Funds deposited by counterparties	19		2		1		55
Restricted cash	469		446		413		414
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,240	$	1,386	$	1,162	$	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)
Balance as of December 31, 2016	$	2,405
Dividends paid to NRG Yield, Inc. public shareholders	(52		)
Distributions to noncontrolling interest	(39		)
Comprehensive loss attributable to noncontrolling interest	(19		)
Non-cash adjustments to noncontrolling interest	88
Contributions from noncontrolling interest	76
Sale of assets to NRG Yield, Inc.	3
Balance as of June 30, 2017	$	2,462

Redeemable Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2016	$	46
Contributions from redeemable noncontrolling interest	42
Comprehensive loss attributable to redeemable noncontrolling interest	(37		)
Balance as of June 30, 2017	$	51

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 flow from operations of $54 million and a decrease of in cash flow from investing of $1 million on the statement of cash flow for the six months ended June 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. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flow from operations of $55 million and a decrease in cash flow from financing of $55 million on the statement of cash flow for the six months ended June 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 2017-07 — 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 2016-02 — 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. While this review is still in process, NRG believes the adoption of Topic 842 will have a material impact 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. While the impact remains subject to continued review, the Company does not believe the adoption of Topic 606 will have a material impact on its financial statements.

Note 3 — Discontinued Operations and Dispositions

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 has 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 has 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:



	Period from April 1, 2017 through June 14, 2017			Three months ended June 30, 2016			Period from January 1, 2017 through June 14, 2017			Six months ended June 30, 2016
(In millions)	Period from April 1, 2017 through June 14, 2017			Three months ended June 30, 2016			Period from January 1, 2017 through June 14, 2017			Six months ended June 30, 2016
Operating revenues	$	265		$	398		$	646		$	977
Operating costs and expenses	(327		)	(474		)	(700		)	(941		)
Gain on sale of assets	—			—			—			32
Other expenses	(54		)	(40		)	(98		)	(84		)
Loss from operations of discontinued components, before tax	(116		)	(116		)	(152		)	(16		)
Income tax expense/(benefit)	8			—			9			(1		)
Loss from operations of discontinued components	(124		)	(116		)	(161		)	(15		)
Interest income - affiliate	3			3			6			6
Loss from operations of discontinued components, net of tax	(121		)	(113		)	(155		)	(9		)
Pre-tax loss on deconsolidation	(208		)	—			(208		)	—
Settlement consideration and services credit	(289		)	—			(289		)	—
Pension liability assumption	(119		)	—			(119		)	—
Advisory and consulting fees	(4		)	—			(4		)	—
Loss on disposal of discontinued components, net of tax	(620		)	—			(620		)	—
Loss from discontinued operations, net of tax	$	(741	)	$	(113	)	$	(775	)	$	(9	)

The following table summarizes the major classes of assets and liabilities classified as discontinued operations as of December 31, 2016. As noted above, NRG no longer consolidates GenOn for financial reporting purposes as of June 30, 2017.



(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	348
Non-current liabilities - discontinued operations	$	3,209

Restructuring Support Agreement

Prior to the GenOn Entities filing for relief under the Bankruptcy Code, 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, on June 12, 2017, 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 June 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. GenOn’s pension liability as of June 30, 2017 was approximately $119 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 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.

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, 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 June 30, 2017 of $119 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.

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 30, 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 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 $41.5 million, excluding working capital adjustments. 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.

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 June 30, 2017, the Company's remaining 35% interest in EVgo of $3 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 June 30, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	25	$	24	$	34	$	34
Liabilities:
Long-term debt, including current portion^(b)	17,086		17,246		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 June 30, 2017 and December 31, 2016:



	As of June 30, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	9,398	$	7,848	$	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 June 30, 2017
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	18	$	18
Available-for-sale securities	4		—		—		4
Nuclear trust fund investments:
Cash and cash equivalents	11		—		—		11
U.S. government and federal agency obligations	45		—		—		45
Federal agency mortgage-backed securities	—		71		—		71
Commercial mortgage-backed securities	—		17		—		17
Corporate debt securities	—		109		—		109
Equity securities	319		—		61		380
Foreign government fixed income securities	—		4		—		4
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	186		535		110		831
Interest rate contracts	—		39		—		39
Total assets	$	566	$	775	$	189	$	1,530
Derivative liabilities:
Commodity contracts	292		496		121		909
Interest rate contracts	—		95		—		95
Total liabilities	$	292	$	591	$	121	$	1,004



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

There were no transfers during the three and six months ended June 30, 2017 and 2016 between Levels 1 and 2. The following tables reconcile, for the three and six months ended June 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)
	Three months ended June 30, 2017										Six months ended June 30, 2017
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	18	$	58	$	(56	)	$	20		$	17	$	54	$	(68	)	$	3
Total gains — realized/unrealized:
Included in earnings	—		—		40			40			1		—		46			47
Included in nuclear decommissioning obligation	—		3		—			3			—		7		—			7
Purchases	—		—		5			5			—		—		9			9
Transfers into Level 3 ^(b)	—		—		3			3			—		—		(5		)	(5		)
Transfers out of Level 3 ^(b)	—		—		(3		)	(3		)	—		—		7			7
Ending balance as of June 30, 2017	$	18	$	61	$	(11	)	$	68		$	18	$	61	$	(11	)	$	68
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of June 30, 2017	$	—	$	—	$	22		$	22		$	—	$	—	$	7		$	7


(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)
	Three months ended June 30, 2016												Six months ended June 30, 2016
(In millions)	Debt Securities			Trust Fund Investments			Derivatives^(a)			Total			Debt Securities			Trust Fund Investments			Derivatives^(a)			Total
Beginning balance	$	17		$	52		$	(2	)	$	67		$	17		$	54		$	(22	)	$	49
Total gains/(losses) — realized/unrealized:
Included in earnings	—			—			23			23			—			—			9			9
Included in OCI	(1		)	—			—			(1		)	(1		)	—			—			(1		)
Included in nuclear decommissioning obligations	—			(1		)	—			(1		)	—			(4		)	—			(4		)
Purchases	—			—			22			22			—			1			27			28
Transfers into Level 3 ^(b)	—			—			(20		)	(20		)	—			—			7			7
Transfers out of Level 3 ^(b)	—			—			(5		)	(5		)	—			—			(3		)	(3		)
Ending balance as of June 30, 2016	$	16		$	51		$	18		$	85		$	16		$	51		$	18		$	85
Gains/(losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of June 30, 2016	$	—		$	—		$	11		$	11		$	—		$	—		$	(7	)	$	(7	)


(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 June 30, 2017, contracts valued with prices provided by models and other valuation techniques make up 13% of the total derivative assets and 12% 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 June 30, 2017 and December 31, 2016:



	Significant Unobservable Inputs
	June 30, 2017
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	57	$	78	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	115	$	30
FTRs	53		43		Discounted Cash Flow	Auction Prices (per MWh)	(29		)	27		—
	$	110	$	121



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

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



Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price Power	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price 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 June 30, 2017, there is no credit reserve. As of December 31, 2016, the credit reserve resulted in 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 June 30, 2017, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $145 million with net exposure of $17 million. NRG held collateral (cash and letters of credit) against those positions of $137 million. Approximately 75% 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	89	%
Financial institutions	11
Total as of June 30, 2017	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	78	%
Non-Investment grade/Non-Rated	22
Total as of June 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 $43 million as of June 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 June 30, 2017, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.3 billion, including $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 June 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 June 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)
Cash and cash equivalents	$	11	$	—	$	—	—	$	25	$	—	$	—	—
U.S. government and federal agency obligations	45		2		—		11	73		1		—		11
Federal agency mortgage-backed securities	71		1		1		24	62		1		1		25
Commercial mortgage-backed securities	17		—		—		24	17		—		1		26
Corporate debt securities	109		2		1		10	84		1		2		11
Equity securities	380		245		—		—	346		214		—		—
Foreign government fixed income securities	4		—		—		7	3		—		—		9
Total	$	637	$	250	$	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.



	Six months ended June 30,
	2017		2016
	(In millions)
Realized gains	$	3	$	3
Realized losses	3		2
Proceeds from sale of securities	277		267

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 June 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 June 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 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 June 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
		June 30, 2017			December 31, 2016
Category	Units	(In millions)
Emissions	Short Ton	(2		)	—
Coal	Short Ton	22			35
Natural Gas	MMBtu	45			(53		)
Oil	Barrel	—			1
Power	MWh	24			7
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,701		$	3,429
Equity	Shares	1			1

The increase in the natural gas position was primarily the result of additional generation and retail hedge positions. The increase in the power position was primarily the result of additional 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
	Derivative Assets				Derivative Liabilities
	June 30, 2017		December 31, 2016		June 30, 2017		December 31, 2016
	(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	9	$	28
Interest rate contracts long-term	9		12		19		41
Total derivatives designated as cash flow hedges	9		12		28		69
Derivatives not designated as cash flow hedges:
Interest rate contracts current	4		—		21		7
Interest rate contracts long-term	26		37		46		12
Commodity contracts current	640		1,067		681		1,057
Commodity contracts long-term	191		132		228		231
Total derivatives not designated as cash flow hedges	861		1,236		976		1,307
Total derivatives	$	870	$	1,248	$	1,004	$	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 of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of June 30, 2017	(In millions)
Commodity contracts:
Derivative assets	$	831		$	(730	)	$	(2	)	$	99
Derivative liabilities	(909		)	730			121			(58		)
Total commodity contracts	(78		)	—			119			41
Interest rate contracts:
Derivative assets	39			(2		)	—			37
Derivative liabilities	(95		)	2			—			(93		)
Total interest rate contracts	(56		)	—			—			(56		)
Total derivative instruments	$	(134	)	$	—		$	119		$	(15	)



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



	Interest Rate Contracts
	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(In millions)
Accumulated OCI beginning balance	$	(61	)	$	(150	)	$	(66	)	$	(101	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	3			7			6			10
Mark-to-market of cash flow hedge accounting contracts	(9		)	(22		)	(7		)	(74		)
Accumulated OCI ending balance, net of $16, and $26 tax	$	(67	)	$	(165	)	$	(67	)	$	(165	)
Losses expected to be realized from OCI during the next 12 months, net of $3 tax	$	15					$	15

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 six months ended June 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 June 30,						Six months ended June 30,
	2017			2016			2017			2016
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	22		$	(18	)	$	25		$	(45	)
Reversal of acquired loss/(gain) positions related to economic hedges	1			(2		)	1			(4		)
Net unrealized gains/(losses) on open positions related to economic hedges	36			(13		)	15			77
Total unrealized mark-to-market gains/(losses) for economic hedging activities	59			(33		)	41			28
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(4		)	2			(19		)	10
Net unrealized gains on open positions related to trading activity	16			11			17			22
Total unrealized mark-to-market gains/(losses) for trading activity	12			13			(2		)	32
Total unrealized gains/(losses)	$	71		$	(20	)	$	39		$	60



	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
	(In millions)
Unrealized gains/(losses) included in operating revenues	$	53		$	(460	)	$	157		$	(390	)
Unrealized gains/(losses) included in cost of operations	18			440			(118		)	450
Total impact to statement of operations — energy commodities	$	71		$	(20	)	$	39		$	60
Total impact to statement of operations — interest rate contracts	$	(24	)	$	(7	)	$	(19	)	$	(18	)

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 six months ended June 30, 2017, the $15 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward sales of PJM electricity and New York capacity due to decreases in PJM electricity and New York capacity prices, which was offset by a decrease in value of forward purchases of natural gas and coal due to decreases in natural gas and coal prices.

For the six months ended June 30, 2016, the $77 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT electricity and natural gas due to increases in ERCOT power and 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 June 30, 2017, was $36 million. The collateral required for contracts with credit rating contingent features as of June 30, 2017, was $39 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 $6 million as of June 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.

2016 Impairment 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.

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)	June 30, 2017			December 31, 2016			June 30, 2017 interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	398		$	398		7.625
Senior notes, due 2021	207			207			7.875
Senior notes, due 2022	992			992			6.250
Senior notes, due 2023	869			869			6.625
Senior notes, due 2024	733			733			6.250
Senior notes, due 2026	1,000			1,000			7.250
Senior notes, due 2027	1,250			1,250			6.625
Term loan facility, due 2023	1,881			1,891			L+2.25
Tax-exempt bonds	455			455			4.125 - 6.00
Subtotal NRG recourse debt	7,785			7,795
Non-recourse debt:
NRG Yield Operating LLC Senior Notes, due 2024	500			500			5.375
NRG Yield Operating LLC Senior Notes, due 2026	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
El Segundo Energy Center, due 2023	414			443			L+1.625 - L+2.25
Marsh Landing, due 2017 and 2023	358			370			L+1.750 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	939			965			5.696 - 7.015
Walnut Creek, term loans due 2023	299			310			L+1.625
Utah Portfolio, due 2022	284			287			L+2.625
Tapestry, due 2021	166			172			L+1.625
CVSR, due 2037	757			771			2.339 - 3.775
CVSR HoldCo, due 2037	193			199			4.680
Alpine, due 2022	142			145			L+1.750
Energy Center Minneapolis, due 2017 and 2025	85			96			5.95 - 7.25
Energy Center Minneapolis, due 2031	125			125			3.55
Viento, due 2023	169			178			L+2.75
NRG Yield - other	569			540			various
Subtotal NRG Yield debt (non-recourse to NRG)	5,983			6,084
Ivanpah, due 2033 and 2038	1,108			1,113			2.285 - 4.256
Carlsbad Energy Project	345			—			4.120
Agua Caliente, due 2037	843			849			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	89			—			5.430
Cedro Hill, due 2025	156			163			L+1.75
Midwest Generation, due 2019	194			231			4.390
NRG Other	622			468			various
Subtotal other NRG non-recourse debt	3,357			2,824
Subtotal all non-recourse debt	9,340			8,908
Subtotal long-term debt (including current maturities)	17,125			16,703
Capital leases	6			6			various
Subtotal long-term debt and capital leases (including current maturities)	17,131			16,709
Less current maturities	(1,042		)	(516		)
Less debt issuance costs	(208		)	(188		)
Discounts	(39		)	(48		)
Total long-term debt and capital leases	$	15,842		$	15,957

(a) As of June 30, 2017, L+ equals 3 month LIBOR plus x%, with the exception of the Utah Portfolio term loans.

Recourse Debt

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 June 30, 2017, no cash borrowings were outstanding on the revolver.

Senior Notes

Issuance of 2026 Senior Notes

On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026.

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

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 June 30, 2017, there was $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 and Dispositions, 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 June 30, 2017, $345 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 million as of June 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 $95 million as of June 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)	June 30, 2017		December 31, 2016
Current assets	$	84	$	87
Net property, plant and equipment	1,493		1,534
Other long-term assets	1,024		954
Total assets	2,601		2,575
Current liabilities	63		59
Long-term debt	424		442
Other long-term liabilities	187		183
Total liabilities	674		684
Noncontrolling interests	600		529
Net assets less noncontrolling interests	$	1,327	$	1,362

Note 10 — Changes in Capital Structure

As of June 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
Balance as of December 31, 2016	417,583,825	(102,140,814	)	315,443,011
Shares issued under LTIPs	397,287	—		397,287
Shares issued under ESPP	—	282,530		282,530
Balance as of June 30, 2017	417,981,112	(101,858,284	)	316,122,828

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

On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the ESPP. As of June 30, 2017, there were 3,385,289 shares of treasury stock available for issuance under the ESPP. In July 2017, 278,240 shares of NRG common stock were issued to employee accounts from treasury stock 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 six months ended June 30, 2017:



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

On July 20, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2017, to stockholders of record as of August 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 loss per share is shown in the following table:



	Three months ended June 30,						Six months ended June 30,
(In millions, except per share data)	2017			2016			2017			2016
Basic and diluted loss per share attributable to NRG Energy, Inc. common stockholders
Net loss attributable to NRG Energy, Inc.	$	(626	)	$	(271	)	$	(790	)	$	(189	)
Dividends for preferred shares	—			—			—			5
Gain on redemption of 2.822% redeemable perpetual preferred stock	—			(78		)	—			(78		)
Loss available for common stockholders	$	(626	)	$	(193	)	$	(790	)	$	(116	)
Weighted average number of common shares outstanding - basic and diluted	316			315			316			315
Loss per weighted average common share — basic and diluted	$	(1.98	)	$	(0.61	)	$	(2.50	)	$	(0.37	)

The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted loss per share:



	Three months ended June 30,		Six months ended June 30,
(In millions of shares)	2017	2016	2017	2016
Equity compensation plans	6	3	6	3
Total	6	3	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. The financial information for the three and six months ended June 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 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 and Dispositions, 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 June 30, 2017	(In millions)
Operating revenues^(a)	$	882		$	1,603	$	123		$	284		$	3		$	(194	)	$	2,701
Depreciation and amortization	95			29		50			78			8			—			260
Impairment losses	41			—		22			—			—			—			63
Equity in (losses)/earnings of unconsolidated affiliates	(15		)	—		(2		)	16			3			(5		)	(3		)
(Loss)/income from continuing operations before income taxes	(89		)	330		(52		)	53			(135		)	(4		)	103
(Loss)/income from continuing operations	(90		)	341		(47		)	45			(146		)	(4		)	99
Loss from discontinued operations, net of tax	—			—		—			—			(741		)	—			(741		)
Net (Loss)/Income	(90		)	341		(47		)	45			(887		)	(4		)	(642		)
Net (Loss)/income attributable to NRG Energy, Inc.	$	(90	)	$	341	$	(22	)	$	50	—	$	(920	)	$	15		$	(626	)
Total assets as of June 30, 2017	$	8,539		$	2,439	$	5,193		$	8,513		$	10,954		$	(10,433	)	$	25,205



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	171	$	1	$	10	$	3	$	9	$	—	$	194



	Generation^(a)			Retail^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)			Eliminations			Total
Three months ended June 30, 2016	(In millions)
Operating revenues^(a)	$	504		$	1,536	$	101		$	283	$	10		$	(186	)	$	2,248
Depreciation and amortization	97			29		47			75		14			—			262
Impairment losses	17			—		27			—		12			—			56
Equity in earnings/(losses) of unconsolidated affiliates	2			—		(2		)	14		27			(37		)	4
Loss on sale of assets	—			—		—			—		(83		)	—			(83		)
Loss on debt extinguishment, net	—			—		—			—		(80		)	—			(80		)
(Loss)/income from continuing operations before income taxes	(458		)	657		(75		)	76		(295		)	(43		)	(138		)
(Loss)/income from continuing operations	(458		)	657		(71		)	64		(312		)	(43		)	(163		)
Loss from discontinued operations, net of tax	—			—		—			—		(113		)	—			(113		)
Net (Loss)/Income	(458		)	657		(71		)	64		(425		)	(43		)	(276		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(458	)	$	661	$	(66	)	$	48	$	(449	)	$	(7	)	$	(271	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	166	$	1	$	4	$	2	$	13	$	—	$	186



	Generation^(a)			Retail ^(a)		Renewables^(a)(b)			NRG Yield		Corporate^(a)			Eliminations			Total
Six months ended June 30, 2017	(In millions)
Operating revenues^(a)	$	1,848		$	2,938	$	220		$	502	$	11		$	(436	)	$	5,083
Depreciation and amortization	192			57		99			153		16			—			517
Impairment losses	41			—		22			—		—			—			63
Equity in (losses)/earnings of unconsolidated affiliates	(28		)	—		(3		)	35		7			(9		)	2
(Loss)/income from continuing operations before income taxes	(54		)	303		(89		)	51		(273		)	(9		)	(71		)
(Loss)/Income from continuing operations	(56		)	311		(79		)	44		(281		)	(9		)	(70		)
Loss from discontinued operations, net of tax	—			—		—			—		(775		)	—			(775		)
Net (Loss)/Income	(56		)	311		(79		)	44		(1,056		)	(9		)	(845		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(56	)	$	311	$	(26	)	$	58	$	(1,089	)	$	12		$	(790	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	406	$	11	$	4	$	—	$	15	$	—	$	436



	Generation^(a)(c)			Retail^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)			Eliminations			Total
Six months ended June 30, 2016	(In millions)
Operating revenues^(a)	$	1,637		$	2,906	$	197		$	517	$	28		$	(378	)	$	4,907
Depreciation and amortization	197			57		95			149		30			—			528
Impairment losses	17			—		27			—		12			—			56
Equity in (losses)/earnings of unconsolidated affiliates	(5		)	—		(8		)	18		6			(14		)	(3		)
Loss on sale of assets	—			—		—			—		(83		)	—			(83		)
Impairment loss on investment	(137		)	—		—			—		(2		)	—			(139		)
Loss on debt extinguishment, net	—			—		—			—		(69		)	—			(69		)
(Loss)/income from continuing operations before income taxes	(433		)	808		(122		)	78		(495		)	(9		)	(173		)
(Loss)/income from continuing operations	(433		)	807		(111		)	66		(540		)	(9		)	(220		)
Loss from discontinued operations, net of tax	—			—		—			—		(9		)	—			(9		)
Net (Loss)/Income	(433		)	807		(111		)	66		(549		)	(9		)	(229		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(433	)	$	807	$	(96	)	$	58	$	(558	)	$	33		$	(189	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	330	$	5	$	8	$	6	$	29	$	—	$	378

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended June 30,						Six months ended June 30,
(In millions except otherwise noted)	2017			2016			2017			2016
Income/(Loss) before income taxes	$	103		$	(138	)	$	(71	)	$	(173	)
Income tax expense/(benefit) from continuing operations	4			25			(1		)	47
Effective tax rate	3.9		%	(18.1		)%	1.4		%	(27.2		)%

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

For the three and six months ended June 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense resulting from the change in the valuation allowance, amortization of indefinite lived assets, inclusion of consolidated partnerships and the impact of state income taxes.

Uncertain Tax Benefits

As of June 30, 2017, NRG has recorded a non-current tax liability of $39 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the six months ended June 30, 2017, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of June 30, 2017, NRG had cumulative interest and penalties related to these uncertain tax benefits of $4 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 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 and Dispositions, 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 six months ended June 30, 2017, NRG recorded other income - affiliate related to these services of $42 million and $90 million, respectively. For the three and six months ended June 30, 2016, NRG recorded other income - affiliate related to these services of $48 million and $96 million, respectively.

In addition, as described in Note 3, Discontinued Operations and Dispositions, 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.

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 June 30, 2017 and December 31, 2016, $140 million and $272 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of June 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 June 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 June 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 June 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 15 — 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 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 June 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. The CPUC approved the amendments without modification on May 11, 2017 and the appeal period expired 30 days later with no appeals filed.

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.

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 the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operation, or cash flows.

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 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. 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 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. The parties to the New Jersey action are seeking to have the New Jersey and California litigation stayed while a final settlement can be executed and approved by the court.

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. 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 June 16, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on September 15, 2017 and defendants' reply is due on November 15, 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. The court heard oral argument on defendants' motion to dismiss on June 20, 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.

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. NRG believes that it was incorrectly named as a party to the lawsuit.

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.

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 and Dispositions, 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, among other things, allege that GenOn Mid-Atlantic was overcharged in connection with the Services Agreement and that GenOn Mid-Atlantic failed to comply with a covenant requiring the maintenance of qualifying credit support. The 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. The litigation has been stayed and a status hearing has been scheduled for September 27, 2017. A claims estimation hearing of this matter is scheduled for September 5, 2017 before the Bankruptcy Court.

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. On June 16, 2017, NRG Texas Power provided notice to BTEC that it was exercising its right to terminate the MIPA due to the project not achieving commercial completion by the contractual expiration date of May 31, 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.

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.

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.

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.

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.

Note 16 — 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, Illinois 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. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. 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.

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.

Current Administration and Changeover at FERC — FERC is currently without a quorum and cannot issue orders in contested proceedings until at least two new Commissioners are 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 connection with several of those orders. There are four vacant positions at FERC. The current administration has nominated three individuals for Commissioner positions and has announced its intent to nominate a fourth Commissioner. NRG’s business may be affected because its generation fleet is subject to changes in FERC regulatory policy.

Note 17 — 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 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 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, fly ash, bottom ash, and flue gas mercury control. 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. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the 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. A petition for reconsideration has been filed by the Utility Solid Waste Activities Group. 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 June 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 remediation plan was within amounts budgeted in early 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 18 — Condensed Consolidating Financial Information

As of June 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, 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 June 30, 2017:



Ace Energy, Inc.	Norwalk Power LLC	NRG Operating Services, Inc.
Allied Home Warranty GP LLC	NRG Advisory Services LLC	NRG Oswego Harbor Power Operations Inc.
Allied Warranty 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 Power Marketing LLC
Bayou Cove Peaking Power, LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Reliability Solutions LLC
BidURenergy, Inc.	NRG Bayou Cove LLC	NRG Renter's Protection LLC
Cabrillo Power I LLC	NRG Business Services LLC	NRG Retail LLC
Cabrillo Power II LLC	NRG Business Solutions LLC	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.
Cirro Energy Services, Inc.	NRG Cedar Bayou Development Company, LLC	NRG Security LLC
Clean Edge Energy LLC	NRG Connected Home LLC	NRG Services Corporation
Conemaugh Power LLC	NRG Connecticut Affiliate Services Inc.	NRG SimplySmart Solutions LLC
Connecticut Jet Power LLC	NRG Construction LLC	NRG South Central Affiliate Services Inc.
Cottonwood Development LLC	NRG Curtailment Solutions Holdings LLC	NRG South Central Generating LLC
Cottonwood Energy Company LP	NRG Curtailment Solutions, Inc	NRG South Central Operations Inc.
Cottonwood Generating Partners I LLC	NRG Development Company Inc.	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 LLC
Devon Power LLC	NRG Dunkirk Operations Inc.	NRG Texas Holding Inc.
Dunkirk Power LLC	NRG El Segundo Operations Inc.	NRG Texas LLC
Eastern Sierra Energy Company LLC	NRG Energy Efficiency-L LLC	NRG Texas Power LLC
El Segundo Power, LLC	NRG Energy Labor Services LLC	NRG Warranty Services LLC
El Segundo Power II LLC	NRG ECOKAP Holdings LLC	NRG West Coast LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Western Affiliate Services Inc.
Energy Choice Solutions LLC	NRG Energy Services International Inc.	O'Brien Cogeneration, Inc. II
Energy Plus Holdings LLC	NRG Energy Services LLC	ONSITE Energy, Inc.
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	Oswego Harbor Power LLC
Energy Protection Insurance Company	NRG Greenco	RE Retail Receivables, LLC
Everything Energy LLC	NRG Home & Business Solutions LLC	Reliant Energy Northeast LLC
Forward Home Security, LLC	NRG Home Services LLC	Reliant Energy Power Supply, LLC
GCP Funding Company, LLC	NRG Home Solutions LLC	Reliant Energy Retail Holdings, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Services, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	RERH Holdings, LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	Saguaro Power LLC
Huntley Power LLC	NRG HQ DG LLC	Somerset Operations Inc.
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Power LLC
Independence Energy Group LLC	NRG Ilion Limited Partnership	Texas Genco Financing Corp.
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
Langford Wind Power, LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Services, LP
Louisiana Generating LLC	NRG Middletown Operations Inc.	US Retailers LLC
Meriden Gas Turbines LLC	NRG Montville Operations Inc.	Vienna Operations Inc.
Middletown Power LLC	NRG New Roads Holdings LLC	Vienna Power LLC
Montville Power LLC	NRG North Central Operations Inc.	WCP (Generation) Holdings 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 June 30, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,758		$	989		$	—		$	(46	)	$	2,701
Operating Costs and Expenses
Cost of operations	1,307			558			16			(44		)	1,837
Depreciation and amortization	102			150			8			—			260
Impairment losses	42			21			—			—			63
Selling, general and administrative	86			38			100			(1		)	223
Acquisition-related transaction and integration costs	—			1			—			—			1
Development activity expenses	—			13			5			—			18
Total operating costs and expenses	1,537			781			129			(45		)	2,402
Other income - affiliate	—			—			42			—			42
Gain on sale of assets	2			—			—			—			2
Operating Income/(Loss)	223			208			(87		)	(1		)	343
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	57			(22		)	(123		)	88			—
Equity in earnings/(losses) of unconsolidated affiliates	—			676			(645		)	(34		)	(3		)
Other income	—			7			3			—			10
Interest expense	(4		)	(121		)	(122		)				(247		)
Total other income/(expense)	53			540			(887		)	54			(240		)
Income/(Loss) from Continuing Operations Before Income Taxes	276			748			(974		)	53			103
Income tax expense/(benefit)	113			267			(376		)	—			4
Income/(Loss) from Continuing Operations	163			481			(598		)	53			99
Loss from Discontinued Operations, net of income tax	—			(741		)	—			—			(741		)
Net Income/(Loss)	163			(260		)	(598		)	53			(642		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(9		)	28			(35		)	(16		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	163		$	(251	)	$	(626	)	$	88		$	(626	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the six months ended June 30, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	3,357		$	1,851		$	—		$	(125	)	$	5,083
Operating Costs and Expenses
Cost of operations	2,568			1,222			31			(125		)	3,696
Depreciation and amortization	203			298			16			—			517
Impairment losses	42			21			—			—			63
Selling, general and administrative	184			84			216			(2		)	482
Acquisition-related transaction and integration costs	—			2			—			—			2
Development activity expenses	—			25			10			—			35
Total operating costs and expenses	2,997			1,652			273			(127		)	4,795
Other income - affiliate	—			—			90			—			90
Gain on sale of assets	4			—			—			—			4
Operating Income/(Loss)	364			199			(183		)	2			382
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(20		)	(57		)	(48		)	125			—
Equity in earnings/(losses) of unconsolidated affiliates	—			707			(669		)	(36		)	2
Other income	1			12			5			—			18
Loss on debt extinguishment	—			(2		)	—			—			(2		)
Interest expense	(7		)	(225		)	(239		)	—			(471		)
Total other (expense)/income	(26		)	435			(951		)	89			(453		)
Income/(Loss) from Continuing Operations Before Income Taxes	338			634			(1,134		)	91			(71		)
Income tax expense/(benefit)	131			237			(369		)	—			(1		)
Income/(Loss) from Continuing Operations	207			397			(765		)	91			(70		)
Loss from Discontinued Operations, net of income tax	—			(775		)	—			—			(775		)
Net Income/(Loss)	207			(378		)	(765		)	91			(845		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(46		)	25			(34		)	(55		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	207		$	(332	)	$	(790	)	$	125		$	(790	)


(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 June 30, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	163	$	(260	)	$	(598	)	$	53		$	(642	)
Other Comprehensive Income/(Loss), net of tax
Unrealized loss on derivatives, net	—		(6		)	(4		)	5			(5		)
Foreign currency translation adjustments, net	—		1			—			—			1
Available-for-sale securities, net	—		—			1			—			1
Defined benefit plans, net	—		28			28			(29		)	27
Other comprehensive income/(loss)	—		23			25			(24		)	24
Comprehensive Income/(Loss)	163		(237		)	(573		)	29			(618		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(10		)	28			(35		)	(17		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	163	$	(227	)	$	(601	)	$	64		$	(601	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the six months ended June 30, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	207	$	(378	)	$	(765	)	$	91		$	(845	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	—		(1		)	—			—			(1		)
Foreign currency translation adjustments, net	5		5			7			(9		)	8
Available-for-sale securities, net	—		—			1			—			1
Defined benefit plans, net	—		29			27			(29		)	27
Other comprehensive income	5		33			35			(38		)	35
Comprehensive Income/(Loss)	212		(345		)	(730		)	53			(810		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(47		)	25			(34		)	(56		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	212	$	(298	)	$	(755	)	$	87		$	(754	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

June 30, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	(19	)	$	363		$	408		$	—		$	752
Funds deposited by counterparties	14			2			3			—			19
Restricted cash	23			443			3			—			469
Accounts receivable - trade, net	783			376			3			—			1,162
Accounts receivable - affiliate	195			5			1			(102		)	99
Inventory	472			241			—			—			713
Derivative instruments	572			142			4			(74		)	644
Cash collateral paid in support of energy risk management activities	252			25			—			—			277
Prepayments and other current assets	106			155			40			—			301
Current assets - held for sale	—			33			—			—			33
Total current assets	2,398			1,785			462			(176		)	4,469
Net property, plant and equipment	4,038			11,049			241			(26		)	15,302
Other Assets
Investment in subsidiaries	1,158			1,040			9,626			(11,824		)	—
Equity investments in affiliates	—			1,123			4			—			1,127
Notes receivable, less current portion	—			9			—			—			9
Goodwill	359			303			—			—			662
Intangible assets, net	560			1,336			—			(3		)	1,893
Nuclear decommissioning trust fund	637			—			—			—			637
Derivative instruments	187			47			26			(34		)	226
Deferred income tax	(6		)	(361		)	578			—			211
Non-current assets held-for-sale	—			10			—			—			10
Other non-current assets	60			537			62			—			659
Total other assets	2,955			4,044			10,296			(11,861		)	5,434
Total Assets	$	9,391		$	16,878		$	10,999		$	(12,063	)	$	25,205
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	622		$	420		$	—		$	1,042
Accounts payable	540			187			30			—			757
Accounts payable — affiliate	724			(441		)	(136		)	(130		)	17
Derivative instruments	590			195			—			(74		)	711
Cash collateral received in support of energy risk management activities	14			2			3						19
Accrued expenses and other current liabilities	298			5			479			28			810
Accrued expenses and other current liabilities-affiliate	—			164			—			—			164
Total current liabilities	2,166			734			796			(176		)	3,520
Other Liabilities
Long-term debt and capital leases	244			8,616			6,982			—			15,842
Nuclear decommissioning reserve	262			—			—			—			262
Nuclear decommissioning trust liability	367			—			—			—			367
Deferred income taxes	308			—			(288		)	—			20
Derivative instruments	179			148			—			(34		)	293
Out-of-market contracts, net	74			145			—			—			219
Non-current liabilities held-for-sale	—			13			—			—			13
Other non-current liabilities	383			316			436			—			1,135
Total non-current liabilities	1,817			9,238			7,130			(34		)	18,151
Total liabilities	3,983			9,972			7,926			(210		)	21,671
Redeemable noncontrolling interest in subsidiaries	—			51			—			—			51
Stockholders’ Equity	5,408			6,855			3,073			(11,853		)	3,483
Total Liabilities and Stockholders’ Equity	$	9,391		$	16,878		$	10,999		$	(12,063	)	$	25,205


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

NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED

CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended June 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) from continuing operations	$	207		$	397			$	(765	)		$	91		$	(70	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			32				—				(4		)	28
Equity in losses/(earnings) of unconsolidated affiliates	—			(13		)		2				9			(2		)
Depreciation and amortization	203			298				16				—			517
Provision for bad debts	17			1				—				—			18
Amortization of nuclear fuel	24			—				—				—			24
Amortization of financing costs and debt discount/premiums	—			20				9				—			29
Amortization of intangibles and out-of-market contracts	12			39				—				—			51
Amortization of unearned equity compensation	—			—				16				—			16
Impairment losses	42			21				—				—			63
Changes in deferred income taxes and liability for uncertain tax benefits	131			237				(360		)		—			8
Changes in nuclear decommissioning trust liability	2			—				—				—			2
Changes in derivative instruments	12			(12		)		7				—			7
Changes in collateral deposits supporting energy risk management activities	(203		)	11				3							(189		)
Proceeds from sale of emission allowances	11			—				—				—			11
Gain on sale of assets	(22		)	—				—				—			(22		)
Cash (used)/provided by changes in other working capital	(298		)	(1,138		)		1,153				(96		)	(379		)
Cash provided/(used) by continuing operations	138			(107		)		81				—			112
Cash used by discontinued operations	—			(38		)		—				—			(38		)
Net Cash Provided/(used) by Operating Activities	138			(145		)		81				—			74
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.								45				(45		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(131		)		—				131			—
Intercompany dividends	—			—				129				(129		)	—
Acquisition of business, net of cash acquired				(16		)		—				—			(16		)
Capital expenditures	(90		)	(436		)		(16		)		—			(542		)
Decrease in notes receivable	—			8				—				—			8
Purchases of emission allowances	(30		)	—								—			(30		)
Proceeds from sale of emission allowances	59			—				—				—			59
Investments in nuclear decommissioning trust fund securities	(279		)	—				—				—			(279		)
Proceeds from sales of nuclear decommissioning trust fund securities	277			—				—				—			277
Proceeds from renewable energy grants and state rebates	8			—			—	—				—			8
Proceeds from sale of assets, net of cash disposed of	35			—				—				—			35
Investments in unconsolidated affiliates	—			(30		)		—				—			(30		)
Other	18			—							—	—			18
Cash (used)/provided by continuing operations	(2		)	(605		)		158				(43		)	(492		)
Cash used by discontinued operations				(53		)									(53		)
Net Cash (Used)/Provided by Investing Activities	(2		)	(658		)		158				(43		)	(545		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(45		)		—				45			—
Payments (for)/from intercompany loans	(122		)	369				(247		)		—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—				131				(131		)	—
Intercompany dividends				(129		)						129			—
Payment of dividends to common and preferred stockholders	—			—				(19		)		—			(19		)
Net receipts from settlement of acquired derivatives that include financing elements	—			2				—				—			2
Proceeds from issuance of long-term debt	—			741				205				—			946
Payments for short and long-term debt	—			(316		)		(214		)		—			(530		)
Receivable from affiliate	—			(125		)		—				—			(125		)
Contributions to, net of distributions from, noncontrolling interest in subsidiaries	—			14				—				—			14
Payment of debt issuance costs	—			(32		)		(4		)		—			(36		)
Other - contingent consideration				(10		)						—			(10		)
Cash (used)/provided by continuing operations	(122		)	469				(148		)		43			242
Cash used by discontinued operations	—			(224		)		—				—			(224		)
Net Cash (Used)/Provided by Financing Activities	(122		)	245				(148		)		43			18
Change in cash from discontinued operations	—			(315		)		—				—			(315		)
Effect of exchange rate changes on cash and cash equivalents	—			(8		)		—				—			(8		)
Net Increase (Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Restricted by Counterparties	14			(251		)		91				—			(146		)
Cash and Cash Equivalents, Restricted Cash, and Funds Restricted by Counterparties at Beginning of Period	4			1,059				323				—			1,386
Cash and Cash Equivalents, Restricted Cash, and Funds Restricted by Counterparties at End of Period	$	18		$	808			$	414			$	—		$	1,240


(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 June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,716		$	569		$	—		$	(37	)	$	2,248
Operating Costs and Expenses
Cost of operations	1,128			342			10			(37		)	1,443
Depreciation and amortization	112			144			6			—			262
Impairment losses	—			56			—			—			56
Selling, general and administrative	93			46			127			—			266
Acquisition-related transaction and integration costs	—			—			5			—			5
Development activity expenses	—			13			5			—			18
Total operating costs and expenses	1,333			601			153			(37		)	2,050
Other income - affiliate							48						48
Loss on sale of assets	—			—			(83		)	—			(83		)
Operating Income/(Loss)	383			(32		)	(188		)	—			163
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(50		)	(35		)	67			18			—
Equity in earnings of unconsolidated affiliates	2			41			7			(46		)	4
Gain on investment	—			—			7			—			7
Other income/(loss), net	1			2			2			—			5
Loss on debt extinguishment	—			(4		)	(76		)	—			(80		)
Interest expense	(4		)	(101		)	(132		)	—			(237		)
Total other expense	(51		)	(97		)	(125		)	(28		)	(301		)
Income/(Loss) from Continuing Operations Before Income Taxes	332			(129		)	(313		)	(28		)	(138		)
Income tax expense/(benefit)	128			(33		)	(70		)	—			25
Income/(Loss) from Continuing Operations	204			(96		)	(243		)	(28		)	(163		)
(Loss)/ Income from Discontinued Operations, net of income tax	—			(116		)	3			—			(113		)
Net Income/(Loss)	204			(212		)	(240		)	(28		)	(276		)
Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest	—			10			31			(46		)	(5		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	204		$	(222	)	$	(271	)	$	18		$	(271	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the six months ended June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	3,655		$	1,310		$	—		$	(58	)	$	4,907
Operating Costs and Expenses
Cost of operations	2,559			754			19			(61		)	3,271
Depreciation and amortization	225			291			12			—			528
Impairment losses	—			56			—			—			56
Selling, general and administrative	191			95			234			—			520
Acquisition-related transaction and integration costs	—			—			6			—			6
Development activity expenses	—			32			12			—			44
Total operating costs and expenses	2,975			1,228			283			(61		)	4,425
Other income - affiliate	—			—			96			—			96
Loss on sale of assets	—			—			(83		)	—			(83		)
Operating Income/(Loss)	680			82			(270		)	3			495
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(81		)	(70		)	342			(191		)	—
Equity in earnings/(losses) of unconsolidated affiliates	3			39			10			(55		)	(3		)
Impairment loss on investment	—			(139		)	—			—			(139		)
Other income, net	2			19			2			(1		)	22
Loss on debt extinguishment	—			(4		)	(65		)	—			(69		)
Interest expense	(7		)	(207		)	(265		)	—			(479		)
Total other (expense)/income	(83		)	(362		)	24			(247		)	(668		)
Income/(Loss) Before Income Taxes	597			(280		)	(246		)	(244		)	(173		)
Income tax expense/(benefit)	228			(94		)	(87		)	—			47
Income/(Loss) from Continuing Operations	369			(186		)	(159		)	(244		)	(220		)
(Loss)/Income from Discontinued Operations, net of income tax	—			(15		)	6			—			(9		)
Net Income/(Loss)	369			(201		)	(153		)	(244		)	(229		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(23		)	36			(53		)	(40		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	369		$	(178	)	$	(189	)	$	(191	)	$	(189	)


(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 June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	204		$	(212	)	$	(240	)	$	(28	)	$	(276	)
Other Comprehensive Income/(Loss), net of tax
Unrealized loss on derivatives, net	—			(5		)	(4		)	6			(3		)
Foreign currency translation adjustments, net	(2		)	(2		)	(4		)	5			(3		)
Available-for-sale securities, net	—			—			(2		)	—			(2		)
Other comprehensive loss	(2		)	(7		)	(10		)	11			(8		)
Comprehensive Income/(Loss)	202			(219		)	(250		)	(17		)	(284		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(1		)	31			(46		)	(16		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	202			(218		)	(281		)	29			(268		)
Gain on redemption of preferred shares	—			—			(78		)	—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	202		$	(218	)	$	(203	)	$	29		$	(190	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the six months ended June 30, 2016

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	369	$	(201	)	$	(153	)	$	(244	)	$	(229	)
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net	—		(55		)	20			—			(35		)
Foreign currency translation adjustments, net	2		2			2			(3		)	3
Available-for-sale securities, net	—		—			1			—			1
Defined benefit plans, net	1		—			—			—			1
Other comprehensive income/(loss)	3		(53		)	23			(3		)	(30		)
Comprehensive Income/(Loss)	372		(254		)	(130		)	(247		)	(259		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(51		)	36			(53		)	(68		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	372		(203		)	(166		)	(194		)	(191		)
Dividends for preferred shares	—		—			5			—			5
Gain on redemption of preferred shares	—		—			(78		)	—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	372	$	(203	)	$	(93	)	$	(194	)	$	(118	)


(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 paid 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			431			324			—			1,151
Non-current liabilities - discontinued operations	—			3,209			—			—			3,209
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 six months ended June 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) from continuing operations	$	369		$	(186	)	$	(159	)	$	(244	)	$	(220	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			40			—			(11		)	29
Equity in (earnings)/losses of unconsolidated affiliates	(3		)	2			—			4			3
Depreciation and amortization	225			291			12			—			528
Provision for bad debts	16			4			—			—			20
Amortization of nuclear fuel	26			—			—			—			26
Amortization of financing costs and debt discount/premiums	—			16			13			—			29
Adjustment for debt extinguishment	—			4			10			—			14
Amortization of intangibles and out-of-market contracts	20			62			—			—			82
Amortization of unearned equity compensation	—			—			16			—			16
Impairment losses	—			195			—			—			195
Changes in deferred income taxes and liability for uncertain tax benefits	460			(208		)	(251		)	—			1
Changes in nuclear decommissioning trust liability	13			—			—			—			13
Changes in derivative instruments	(64		)	54			3			—			(7		)
Changes in collateral deposits supporting energy risk management activities	344			(21		)	—			—			323
Proceeds from sale of emission allowances	47			(30		)	—			—			17
Loss on sale of assets	—			8			75			—			83
Cash (used)/provided by changes in other working capital	(1,148		)	239			386			251			(272		)
Net cash provided by continuing operations	305			470			105			—			880
Cash used by discontinued operations				(69		)							(69		)
Net Cash Provided by Operating Activities	305			401			105			—			811
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			39			(39		)	—
Intercompany dividends	—			—			12			(12		)	—
Acquisition of businesses, net of cash acquired	—			(17		)	—			—			(17		)
Capital expenditures	(80		)	(329		)	(33		)	—			(442		)
Increase in notes receivable	—			(3		)	—			—			(3		)
Purchases of emission allowances	(27		)	—			—			—			(27		)
Proceeds from sale of emission allowances	25			—			—			—			25
Investments in nuclear decommissioning trust fund securities	(280		)	—			—			—			(280		)
Proceeds from sales of nuclear decommissioning trust fund securities	267			—			—			—			267
Proceeds from renewable energy grants and state rebates	—			10			—			—			10
Proceeds from sale of assets, net of cash disposed of	—			—			25			—			25
Investments in unconsolidated affiliates	1			—			—			—			1
Other	27			4			—			—			31
Net cash (used)/provided by continuing operations	(67		)	(335		)	43			(51		)	(410		)
Cash used by discontinued operations				(60		)							(60		)
Net Cash (Used)/Provided by Investing Activities	(67		)	(395		)	43			(51		)	(470		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(39		)	—			39			—
Payments (for)/from intercompany loans	(179		)	45			134			—			—
Intercompany dividends	(52		)	40			—			12			—
Payment of dividends to common and preferred stockholders	—			—			(57		)	—			(57		)
Payment for preferred shares	—			—			(226		)	—			(226		)
Net receipts for settlement of acquired derivatives that include financing elements	—			4			—			—			4
Proceeds from issuance of long-term debt	—			332			2,891			—			3,223
Payments for short and long-term debt	(1		)	(279		)	(3,225		)	—			(3,505		)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			(21		)	—			—			(21		)
Payment of debt issuance costs	—			—			(35		)	—			(35		)
Other	(3		)	(7		)	—			—			(10		)
Net cash used/provided by continuing operations	(235		)	75			(518		)	51			(627		)
Cash provided by discontinued operations				97									97
Net Cash (Used)/Provided by Financing Activities	(235		)	172			(518		)	51			(530		)
Change in cash from discontinued operations				(32		)							(32		)
Effect of exchange rate changes on cash and cash equivalents	—			(3		)	—			—			(3		)
Net Increase (Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Restricted by Counterparties	3			207			(370		)	—			(160		)
Cash and Cash Equivalents, Restricted Cash, and Funds Restricted by Counterparties at Beginning of Period	—			629			693			—			1,322
Cash and Cash Equivalents, Restricted Cash, and Funds Restricted by Counterparties at End of Period	$	3		$	836		$	323		$	—		$	1,162


(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 six months ended June 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 June 30, 2017, by operating segment:



	Global Generation Portfolio^(a)(b)
	(In MW)
	Generation
Generation Type	Gulf Coast	East/West ^(c)	Renewables^(d)		NRG Yield^(e)		Other^(f)	Total Global
Natural gas^(g)	7,835	4,939	—		1,878		—	14,652
Coal	5,114	3,869	—		—		—	8,983
Oil	—	3,642	—		190		—	3,832
Nuclear	1,136	—	—		—		—	1,136
Wind	—	—	944		2,005		—	2,949
Utility Scale Solar	—	—	742		921		—	1,663
Distributed Solar	—	—	133		14		114	261
Total generation capacity^(g)	14,085	12,450	1,819		5,008		114	33,476
Capacity attributable to noncontrolling interest^(h)	—	—	(684	)	(2,252	)	—	(2,936	)
Total net generation capacity	14,085	12,450	1,135		2,756		114	30,540

(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.

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

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

(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.

(g) Natural gas generation does not include 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.


(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 5,002 MWs.

GenOn

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 U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Houston Division. As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries, representing approximately 15,000 MW, were deconsolidated from NRG’s consolidated financial statements.

Transformation Plan

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 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

Minimum Offer Price Rule Exemption Appeal — On July 7, 2017, the D.C. Circuit vacated a FERC order from 2013 related to an exemption to the Minimum Offer Price Rule, or MOPR. In 2012, PJM proposed changes to its MOPR. FERC accepted parts of PJM’s proposal but also created other requirements that were not part of PJM’s proposal. NRG filed an appeal of FERC’s Order. The D.C. Circuit vacated FERC’s ruling addressing its authority to modify rates filed by ISOs and RTOs under Section 205 of the Federal Power Act and concluded that FERC overstepped its authority in implementing a tariff change that was significantly different than that proposed by stakeholders. The decision could affect how generators participate in the PJM Base Residual Auction and could affect other cases where the same arguments have been made.

PJM Capacity Performance Appeals — On or about July 8, 2016, multiple petitions were filed at the D.C. Circuit seeking review of the FERC orders approving PJM’s Capacity Performance revisions to its forward capacity market after motions for rehearing at FERC were denied on May 10, 2016. NRG intervened in these matters on July 29, 2016, and along with other generators and industry trade groups, filed a joint brief in support of FERC’s decision. On June 20, 2017, the D.C Circuit denied the petitions for review. This case governs capacity revenues already received by NRG, as well as the revenues for forward periods.

2020/2021 PJM Auction Results — On May 23, 2017, PJM announced the 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 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 detailed description of 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 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 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 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 an investigatory proceeding looking into New York’s retail market structure, as well as placing 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 to retain those customers. Retail suppliers who cannot meet these conditions will be required to return their customers to energy supply service provided by the local utility. Various parties challenged the NYPSC’s ability to regulate rates charged by competitive suppliers. On July 27, 2017, the Appellate Division issued an order affirming the NYPSC’s ability to regulate the rates charged by competitive suppliers. The evidentiary proceeding is proceeding at the NYPSC. The outcome of this evidentiary and collaborative process, combined with the outcome of the appeal of the Reset Order, could affect the viability of the New York retail energy market.

General

State Out-Of-Market Subsidy Proposals — 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 has opposed those efforts to provide out of market subsidies, and intends to continue opposing them in the 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, 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. Hearings on those topics took place from July 26, 2017 through July 28, 2017. On June 20, 2017, the CEC issued a revised scheduling order that maintains in place the hearings scheduled for addressing issues raised in its order dated March 10, 2017 and adds an additional day of hearings scheduled for September 14, 2017 to address new CAISO studies addressing possible alternatives to gas-fired generation. The CAISO studies will be submitted on August 16, 2017. The CEC’s additional hearings 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 of the second quarter of 2020.

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 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 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 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 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. On June 29, 2017, the EPA asked the D.C. Circuit to keep the case in abeyance pending the review. Due to a recent Executive Order and various steps taken by the current U.S. presidential administration, 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

Gulf Coast Region

Texas Regional Haze — In January 2016, the EPA promulgated a final rule that requires 15 coal-fired units (at eight plants in Texas) to reduce their 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 of the CAA that seeks to improve visibility at national parks. Eight of these 15 units already have scrubbers and seven do not. NRG owns two of the affected units, Limestone units 1 and 2, which already have scrubbers. The rule requires that the Limestone units reduce their SO₂ 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 the rule.

Illinois Union Insurance Company Litigation — On October 2, 2015, the U.S. District Court for the Middle District of Louisiana issued an order granting LaGen’s motion for summary judgment on its claims for declaratory judgment and breach of contract against ILU for its failure to indemnify LaGen for the costs LaGen paid pursuant to the consent decree that resolved the NSR lawsuit which was brought by the U.S. EPA and LA DEQ against LaGen related to Big Cajun II. The court entered judgment in favor of LaGen for approximately $27 million. In addition, the court ruled that LaGen is entitled to approximately $7 million for future consent decree costs as they are incurred. On October 14, 2015, ILU filed a motion to stay execution of the judgment, which was granted on October 19, 2015. Also, on October 14, 2015, ILU filed a notice to appeal the judgment. 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. LaGen reached a settlement of its lawsuit against ILU and the case was dismissed on June 13, 2017.

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 3, Discontinued Operations and Dispositions and Note 14, Related Party Transactions of this Form 10-Q.

Transfers of Assets Under Common Control

•

On March 27, 2017, the Company 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 and Dispositions 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 $41.5 million, excluding working capital adjustments. The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning in 2027.

Financing Activities


•	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 discussed in more detail in Note 8, Debt and Capital Leases of this Form 10-Q.


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

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 Date under 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.

Bacliff Project

On June 16, 2017, the Company provided notice to BTEC New Albany, LLC that NRG Texas Power LLC 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. 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 projected to result in an extended outage. At this time, the 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 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.

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 June 30,									Six months ended June 30,
(In millions except otherwise noted)	2017			2016			Change			2017			2016			Change
Operating Revenues
Energy revenue^(a)	$	656		$	755		$	(99	)	$	1,243		$	1,545		$	(302	)
Capacity revenue ^(a)	297			315			(18		)	559			634			(75		)
Retail revenue	1,605			1,548			57			2,946			2,916			30
Mark-to-market for economic hedging activities	41			(473		)	514			159			(422		)	581
Contract amortization	(14		)	(14		)	—			(29		)	(29		)	—
Other revenues ^(b)	116			117			(1		)	205			263			(58		)
Total operating revenues	2,701			2,248			453			5,083			4,907			176
Operating Costs and Expenses
Cost of sales ^(c)	1,422			1,363			(59		)	2,683			2,679			(4		)
Mark-to-market for economic hedging activities	(18		)	(440		)	(422		)	118			(450		)	(568		)
Contract and emissions credit amortization ^(c)	8			9			1			16			23			7
Operations and maintenance	340			426			86			712			842			130
Other cost of operations	85			85			—			167			177			10
Total cost of operations	1,837			1,443			(394		)	3,696			3,271			425
Depreciation and amortization	260			262			2			517			528			11
Impairment losses	63			56			(7		)	63			56			(7		)
Selling, general and administrative	223			266			43			482			520			38
Acquisition-related transaction and integration costs	1			5			4			2			6			4
Development costs	18			18			—			35			44			9
Total operating costs and expenses	2,402			2,050			(352		)	4,795			4,425			(370		)
Other income - affiliate	42			48			(6		)	90			96			(6		)
Gain/(loss) on sale of assets	2			(83		)	85			4			(83		)	87
Operating Income	343			163			180			382			495			(113		)
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(3		)	4			(7		)	2			(3		)	5
Gain/(Impairment loss) on investment	—			7			(7		)	—			(139		)	139
Other income, net	10			5			5			18			22			(4		)
Loss on debt extinguishment, net	—			(80		)	80			(2		)	(69		)	67
Interest expense	(247		)	(237		)	(10		)	(471		)	(479		)	8
Total other expense	(240		)	(301		)	61			(453		)	(668		)	215
Income/(Loss) from Continuing Operations before Income Taxes	103			(138		)	241			(71		)	(173		)	102
Income tax expense/(benefit)	4			25			(21		)	(1		)	47			(48		)
Income/(Loss) from Continuing Operations	99			(163		)	262			(70		)	(220		)	150
Loss from discontinued operations, net of income tax	(741		)	(113		)	(628		)	(775		)	(9		)	(766		)
Net Loss	(642		)	(276		)	(366		)	(845		)	(229		)	(616		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	(16		)	(5		)	(11		)	(55		)	(40		)	(15		)
Net Loss Attributable to NRG Energy, Inc.	$	(626	)	$	(271	)	$	(355	)	$	(790	)	$	(189	)	$	(601	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.18		$	1.95		63		%	$	3.25		$	2.02		61		%

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



	Average on Peak Power Price ($/MWh)
	Three months ended June 30,
Region	2017		2016		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	46.03	$	24.33	89	%
ERCOT - North^(b)	27.80		22.30		25	%
MISO - Louisiana Hub^(c)	41.81		33.20		26	%
East/West
NY J/NYC^(c)	38.73		30.54		27	%
NEPOOL^(c)	32.19		28.17		14	%
PEPCO (PJM)^(c)	35.37		36.49		(3	)%
PJM West Hub^(c)	33.24		32.07		4	%
CAISO - NP15^(c)	32.31		25.99		24	%
CAISO - SP15^(c)	32.31		25.13		29	%

(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 three months ended June 30, 2017 and 2016, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Three months ended June 30,
Region	2017		2016		Change %
Gulf Coast	$	34.68	$	38.82	(11	)%
East/West	40.17		42.87		(6	)%

Though the average on peak power prices have increased on average by 19%, 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 June 30, 2017 and 2016:



	Three months ended June 30, 2017
	Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	484		$	184		$	668		$	—		$	107		$	175		$	(294	)	$	656
Capacity revenue	68			144			212			—			—			85						297
Retail revenue	—			—			—			1,605			—						—			1,605
Mark-to-market for economic hedging activities	(90		)	13			(77		)	(2		)	(3		)				123			41
Contract amortization	3			—			3									(17		)				(14		)
Other revenue ^(b)	55			21			76			—			19			41			(20		)	116
Operating revenue	520			362			882			1,603			123			284			(191		)	2,701
Cost of fuel	(284		)	(82		)	(366		)	(2		)	(1		)	(7		)	5			(371		)
Other cost of sales^(c)	(79		)	(52		)	(131		)	(1,211		)	(2		)	(7		)	300			(1,051		)
Mark-to-market for economic hedging activities	(15		)	(2		)	(17		)	158			—			—			(123		)	18
Contract and emission credit amortization	(7		)	(1		)	(8		)	—			—			—			—			(8		)
Gross margin	$	135		$	225		$	360		$	548		$	120		$	270		$	(9	)	$	1,289
Less: Mark-to-market for economic hedging activities, net	(105		)	11			(94		)	156			(3		)	—			—			59
Less: Contract and emission credit amortization, net	(4		)	(1		)	(5		)	—			—			(17		)	—			(22		)
Economic gross margin	$	244		$	215		$	459		$	392		$	123		$	287		$	(9	)	$	1,252
Business Metrics
MWh sold (thousands)^(d)(e)	13,958			4,581									1,083			2,089
MWh generated (thousands)^(f)	13,101			3,084									1,083			2,402
(a) Includes International, BETM and Generation eliminations
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(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.
(e) Does not include thermal MWh of 9 thousand or MWt of 418 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 20 thousand or MWt of 418 thousand for thermal generated by NRG Yield.



	Three months ended June 30, 2016
	Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	506		$	206		$	712		$	—		$	91		$	173		$	(221	)	$	755
Capacity revenue	71			159			230			—			—			87			(2		)	315
Retail revenue	—			—			—			1,539			—			—			9			1,548
Mark-to-market for economic hedging activities	(421		)	(123		)	(544		)	(2		)	(2		)	—			75			(473		)
Contract amortization	4			—			4			(1		)	—			(17		)	—			(14		)
Other revenue ^(b)	78			24			102			—			12			40			(37		)	117
Operating revenue	238			266			504			1,536			101			283			(176		)	2,248
Cost of fuel	(225		)	(81		)	(306		)	(1		)	(1		)	(7		)	1			(314		)
Other cost of sales^(c)	(109		)	(57		)	(166		)	(1,122		)	(3		)	(7		)	249			(1,049		)
Mark-to-market for economic hedging activities	32			7			39			476			—			—			(75		)	440
Contract and emission credit amortization	(7		)	(1		)	(8		)	(1		)	—			—			—			(9		)
Gross margin	$	(71	)	$	134		$	63		$	888		$	97		$	269		$	(1	)	$	1,316
Less: Mark-to-market for economic hedging activities, net	(389		)	(116		)	(505		)	474			(2		)	—			—			(33		)
Less: Contract and emission credit amortization, net	(3		)	(1		)	(4		)	(2		)	—			(17		)	—			(23		)
Economic gross margin	$	321		$	251		$	572		$	416		$	99		$	286		$	(1	)	$	1,372
Business Metrics
MWh sold (thousands)^(d)(e)	13,036			4,805									901			2,041
MWh generated (thousands)^(f)	11,770			3,327									901			2,417
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $4 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 9 thousand or MWt of 448 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 32 thousand or MWt of 448 thousand for thermal generated by NRG Yield.

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



	Three months ended June 30,
Weather Metrics	Gulf Coast	East/West
2017
CDDs ^(a)	921	281
HDDs ^(a)	41	380
2016
CDDs	873	273
HDDs	53	410
10 year average
CDDs	957	254
HDDs	75	438

(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

Generation gross margin increased $297 million and economic gross margin decreased $113 million, both of which include intercompany sales, during the three months ended June 30, 2017, compared to the same period in 2016:

The table below describes the decrease in Generation gross margin and economic gross margin:

Gulf Coast Region



	(In millions)
Lower gross margin due to 10% decrease in average realized prices primarily in Texas due to lower hedged power prices	$	(52	)
Lower energy margin due to increased supply cost on load contracts	(18		)
Lower gross margin due to a 14% decrease in nuclear generation driven by the timing of planned outages	(11		)
Lower gross margin due to a 55% decrease in PJM capacity prices and a 45% decrease in volume sold	(8		)
Higher gross margin primarily due to an 3% increase in higher coal generation mainly in Texas driven by timing of planned outages	14
Other	(2		)
Decrease in economic gross margin	$	(77	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	284
Decrease in contract and emission credit amortization	(1		)
Increase in gross margin	$	206

East/West



	(In millions)
Lower gross margin due to a 5% decrease in average realized energy prices coupled with spark spread contraction	$	(20	)
Lower gross margin due to a 12% decrease in PJM capacity volumes sold coupled with a 9% decrease in NY/NE realized capacity prices	(13		)
Lower gross margin from commercial optimization activities	(12		)
Other	9
Decrease in economic gross margin	$	(36	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	127
Increase in gross margin	$	91

Retail gross margin and economic gross margin

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



	Three months ended June 30,
(In millions except otherwise noted)	2017			2016
Retail revenue	$	1,515		$	1,478
Supply management revenue	52			40
Capacity revenue	38			21
Customer mark-to-market	(2		)	(2		)
Contract amortization	—			(1		)
Operating revenue^(a)	1,603			1,536
Cost of sales ^(b)	(1,213		)	(1,123		)
Mark-to-market for economic hedging activities	158			476
Contract amortization	—			(1		)
Gross Margin	$	548		$	888
Less: Mark-to-market for economic hedging activities, net	156			474
Less: Contract and emission credit amortization, net	—			(2		)
Economic Gross Margin	$	392		$	416

Business Metrics
Mass electricity sales volume - GWh - Gulf Coast	9,234			8,674
Mass electricity sales volume - GWh - All other regions	1,357			1,444
C&I electricity sales volume — GWh - All regions	5,308			4,671
Natural gas sales volumes (MDth)	438			328
Average Retail Mass customer count (in thousands)	2,859			2,765
Ending Retail Mass customer count (in thousands)	2,887			2,771


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


(b)	Includes intercompany purchases of $286 million and $184 million in 2017 and 2016, respectively.

Retail gross margin decreased $340 million and economic gross margin decreased $24 million for the three months ended June 30, 2017, compared to the same period in 2016, due to:



	(In millions)
Lower gross margin due to lower revenue of $16 million, primarily due to lower rates to customers and higher supply costs of $25 million driven primarily by an increase in power prices	$	(41	)
Lower gross margin of $5 million due to a reduction in load of 173,000 MWhs and $3 million in lower margin due to the unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 compared to 2016	(8		)
Higher gross margin due to higher volume driven by higher average customer usage and mix	25
Decrease in economic gross margin	$	(24	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(318		)
Increase in contract and emission credit amortization	2
Decrease in gross margin	$	(340	)

Renewables gross margin and economic gross margin

Renewables gross margin increased $23 million and economic gross margin increased $24 million for the three months ended June 30, 2017, compared to the same period in 2016, primarily driven by higher volume and pricing at Ivanpah solar plant.

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 $92 million during the three months ended June 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 June 30, 2017
	Generation
	Gulf Coast			East/West^(a)			Retail			Renewables			Eliminations^(b)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(7	)	$	(11	)	$	(1	)	$	—		$	50		$	31
Net unrealized (losses)/gains on open positions related to economic hedges	(83		)	24			(1		)	(3		)	73			10
Total mark-to-market (losses)/gains in operating revenues	$	(90	)	$	13		$	(2	)	$	(3	)	$	123		$	41
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(4	)	$	—		$	45		$	—		$	(50	)	$	(9	)
Reversal of acquired loss positions related to economic hedges	—			—			1			—			—			1
Net unrealized (losses)/gains on open positions related to economic hedges	(11		)	(2		)	112			—			(73		)	26
Total mark-to-market (losses)/gains in operating costs and expenses	$	(15	)	$	(2	)	$	158		$	—		$	(123	)	$	18


(a)	Includes International and BETM.


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



	Three months ended June 30, 2016
	Generation
	Gulf Coast			East/West^(a)			Retail			Renewables			Eliminations^(b)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(129	)	$	(21	)	$	(1	)	$	—		$	35		$	(116	)
Net unrealized (losses)/gains on open positions related to economic hedges	(292		)	(102		)	(1		)	(2		)	40			(357		)
Total mark-to-market (losses)/gains in operating revenues	$	(421	)	$	(123	)	$	(2	)	$	(2	)	$	75		$	(473	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	7		$	5		$	121		$	—		$	(35	)	$	98
Reversal of acquired (gain)/loss positions related to economic hedges	—			(3		)	1			—			—			(2		)
Net unrealized gains/(losses) on open positions related to economic hedges	25			5			354			—			(40		)	344
Total mark-to-market gains/(losses) in operating costs and expenses	$	32		$	7		$	476		$	—		$	(75	)	$	440


(a)	Includes International and BETM.


(b)	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 June 30, 2017, the $41 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 and New York capacity prices, partially offset by a decrease in value of open positions as a result of ERCOT heat rate expansion. The $18 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of ERCOT heat rate expansion, partially offset by a decrease in value of open positions as a result of decrease in coal prices and the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the three months ended June 30, 2016, the $473 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in value of open positions as a result of increases in gas and electricity prices, in addition to the reversal of previously recognized unrealized gains on contracts that settled during the period. The $440 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of increases in natural gas, coal, and ERCOT electricity prices, in addition to the reversal of previously recognized unrealized losses on contracts that settled during the period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended June 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 June 30,
(In millions)	2017		2016
Trading gains
Realized	$	14	$	23
Unrealized	12		13
Total trading gains	$	26	$	36

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)
Three months ended June 30, 2017	$	107	$	108	$	56	$	34	$	46	$	—	$	(11	)	$	340
Three months ended June 30, 2016	$	141	$	140	$	60	$	44	$	49	$	—	$	(8	)	$	426


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

Operations and maintenance expense decreased by $86 million for the three months ended June 30, 2017, compared to the same period in 2016, due to the following:



	(In millions)
Decrease in Gulf Coast operation and maintenance expense due primarily to lower expenses at Big Cajun II in 2017	$	(25	)
Decrease in operation and maintenance expenses due primarily to major maintenance activities and environmental control work at Midwest Generation in 2016	(39		)
Decrease in Renewables operation and maintenance expense primarily due to unplanned outages at Ivanpah in 2016	(10		)
Decrease in Retail operation and maintenance expense due primarily to a reduction in employee expenses	(4		)
Other	(8		)
	$	(86	)

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 June 30, 2017	$	48	$	106	$	14	$	6	$	49	$	223
Three months ended June 30, 2016	74		112		15		3		62		266

Selling, general and administrative expenses decreased by $43 million for the three months ended June 30, 2017, compared to the same period in 2016. The decrease was primarily related to $22 million of costs incurred in 2016 related to severance and employee costs, partially offset by $6 million related to advisors engaged to assist the Company in its current strategic review in the current period. The remaining decreases in selling, general and administrative expenses quarter over quarter is due to the Company's continued focus on cost management.

Loss on Sale of Assets

During the three months ended June 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners as described in Note 3, Discontinued Operations and Dispositions, of this Form 10-Q. In connection with the sale, the Company recorded a loss on sale of $83 million, which included $56 million for the accrual of NRG's remaining obligation to the CPUC.

Loss on Debt Extinguishment

A loss on debt extinguishment of $80 million was recorded for the three months ended June 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 increased by $10 million for the three months ended June 30, 2017, compared to the same period in 2016 due to the following:



	(In millions)
Increase in derivative interest expense from changes in fair value of interest rate swaps	$	22
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016	6
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	2
Decrease due to the repurchase of Senior Notes in 2016 of $46 million, partially offset by Senior Notes issued in 2016 of $31 million	(15		)
Decrease due to the redemption of bonds related to Peaker Finance Company, due 2019 during 2016	(5		)
	$	10

Income Tax Expense

For the three months ended June 30, 2017, NRG recorded income tax expense of $4 million on pre-tax income of $103 million. For the same period in 2016, NRG recorded income tax expense of $25 million on a pre-tax loss of $138 million. The effective tax rate was 3.9% and (18.1)% for the three months ended June 30, 2017 and 2016, respectively.

For the three months ended June 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.

For the three months ended June 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense resulting from the change in the valuation allowance, amortization of indefinite lived assets, inclusion of consolidated partnerships and the impact of state income taxes.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the three months ended June 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, partially offset by NRG Yield, Inc.'s share of net income.

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

For the three months ended June 30, 2017 and 2016, NRG recorded losses from discontinued operations, net of income tax expense/(benefit) of $741 million and $113 million, respectively. Discontinued operations were comprised of the results of GenOn and the recording of certain liabilities in connection with the Restructuring Support Agreement, as further disclosed in Item 1 - Note 3, Discontinued Operations and Dispositions of this Form 10-Q.

Management’s discussion of the results of operations for the six months ended June 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 six months ended June 30, 2017, and 2016. Average on-peak power prices increased primarily due to the increase in natural gas prices for the six months ended June 30, 2017 as compared to the same period in 2016.



	Average on Peak Power Price ($/MWh)
	Six months ended June 30,
Region	2017		2016		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	36.86	$	22.39	65	%
ERCOT - North^(b)	25.28		20.97		21	%
MISO - Louisiana Hub^(c)	38.86		28.52		36	%
East/West
NY J/NYC^(c)	39.20		30.02		31	%
NEPOOL^(c)	30.35		32.02		(5	)%
PEPCO (PJM)^(c)	35.17		36.46		(4	)%
PJM West Hub^(c)	32.88		31.78		3	%
CAISO - NP15^(c)	32.02		26.04		23	%
CAISO - SP15^(c)	30.94		24.94		24	%

(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 six months ended June 30, 2017, and 2016, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Six months ended June 30,
Region	2017		2016		Change %
Gulf Coast	$	34.25	$	39.41	(13	)%
East/West	41.81		43.81		(5	)%

Though the average on peak power prices have increased on average by 18% 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 six months ended June 30, 2017 and 2016:



	Six months ended June 30, 2017
	Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	868		$	408		$	1,276		$	—		$	179		$	289		$	(501	)	$	1,243
Capacity revenue	133			266			399			—			—			164			(4		)	559
Retail revenue	—			—			—			2,939			—			—			7			2,946
Mark-to-market for economic hedging activities	41			4			45			—			3			—			111			159
Contract amortization	6						6			(1		)	—			(34		)	—			(29		)
Other revenue ^(b)	102			20			122			—			38			83			(38		)	205
Operating revenue	1,150			698			1,848			2,938			220			502			(425		)	5,083
Cost of fuel	(498		)	(170		)	(668		)	(7		)	(2		)	(18		)	31			(664		)
Other cost of sales^(c)	(157		)	(124		)	(281		)	(2,204		)	(5		)	(12		)	483			(2,019		)
Mark-to-market for economic hedging activities	(24		)	(3		)	(27		)	20			—			—			(111		)	(118		)
Contract and emission credit amortization	(14		)	(2		)	(16		)	—			—			—			—			(16		)
Gross margin	$	457		$	399		$	856		$	747		$	213		$	472		$	(22	)	$	2,266
Less: Mark-to-market for economic hedging activities, net	17			1			18			20			3			—			—			41
Less: Contract and emission credit amortization, net	(8		)	(2		)	(10		)	(1		)	—			(34		)	—			(45		)
Economic gross margin	$	448		$	400		$	848		$	728		$	210		$	506		$	(22	)	$	2,270
Business Metrics
MWh sold (thousands)^(d)(e)	25,340			9,759									2,012			3,751
MWh generated (thousands)^(f)	23,790			6,101									2,013			4,206
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $14 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 18 thousand or MWt of 987 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 36 thousand or MWt of 987 thousand for thermal generated by NRG Yield.



	Six months ended June 30, 2016
	Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	948		$	534		$	1,482		$	—		$	176		$	301		$	(414	)	$	1,545
Capacity revenue	150			320			470			—			—			170			(6		)	634
Retail revenue	—			—			—			2,909			—			—			7			2,916
Mark-to-market for economic hedging activities	(449		)	(66		)	(515		)	(2		)	(1		)	—			96			(422		)
Contract amortization	7			—			7			(1		)	—			(34		)	(1		)	(29		)
Other revenue ^(b)	131			62			193			—			22			80			(32		)	263
Operating revenue	787			850			1,637			2,906			197			517			(350		)	4,907
Cost of fuel	(401		)	(181		)	(582		)	(4		)	(1		)	(18		)	96			(509		)
Other cost of sales^(c)	(195		)	(162		)	(357		)	(2,144		)	(8		)	(12		)	351			(2,170		)
Mark-to-market for economic hedging activities	35			1			36			510			—			—			(96		)	450
Contract and emission credit amortization	(13		)	(4		)	(17		)	(3		)	—			(6		)	3			(23		)
Gross margin	$	213		$	504		$	717		$	1,265		$	188		$	481		$	4		$	2,655
Less: Mark-to-market for economic hedging activities, net	(414		)	(65		)	(479		)	508			(1		)	—			—			28
Less: Contract and emission credit amortization, net	(6		)	(4		)	(10		)	(4		)	—			(40		)	2			(52		)
Economic gross margin	$	633		$	573		$	1,206		$	761		$	189		$	521		$	2		$	2,679
Business Metrics
MWh sold (thousands)^(d)(e)	24,053			12,190									1,991			3,819
MWh generated (thousands)^(f)	21,500			7,306									1,991			4,456
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $8 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 49 thousand or MWt of 1,001 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 123 thousand or MWt of 1,001 thousand for thermal generated by NRG Yield.

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



	Six months ended June 30,
Weather Metrics	Gulf Coast	Other
2017
CDDs ^(a)	1,125	301
HDDs ^(a)	673	2,008
2016
CDDs	950	292
HDDs	984	2,023
10 year average
CDDs	1,039	271
HDDs	1,161	2,237

(a)

Generation gross margin and economic gross margin

Generation gross margin increased $139 million and economic gross margin decreased $358 million, both of which include intercompany sales, during the six months ended June 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 12% decrease in lower average realized prices primarily in Texas due to lower hedged power prices	$	(149	)
Lower energy margin due to increased supply cost on load contracts	(26		)
Lower gross margin due to a 62% decrease in PJM capacity prices and a 38% decrease in volume sold	(22		)
Lower capacity margin on contract expirations and lower demand	(20		)
Lower gross margin due to an 11% decrease in nuclear generation driven by the timing of planned outages	(18		)
Higher gross margin primarily due to a 16% increase in higher coal generation mainly in Texas driven by timing of planned outages	43
Other	7
Decrease in economic gross margin	$	(185	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	431
Decrease in contract and emission credit amortization	(2		)
Increase in gross margin	$	244

East/West



	(In millions)
Lower gross margin due to a 22% decrease in PJM capacity volumes sold coupled with a 12% decrease in NY/NE realized capacity prices and a 5% decrease in NY/NE capacity volumes	$	(44	)
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	(31		)
Lower gross margin from commercial optimization activities	(31		)
Lower gross margin due to lower load contract volumes coupled with higher supply costs	(29		)
Lower gross margin due to a 16% decrease in generation driven by lower economic generation due to outages and milder weather compared to prior year	(24		)
Lower gross margin due to a 3% decrease in average realized energy prices coupled with spark spread contraction	(17		)
Other	3
Decrease in economic gross margin	$	(173	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	66
Increase in contract and emission credit amortization	2
Decrease in gross margin	$	(105	)

Retail gross margin and economic gross margin

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



	Six months ended June 30,
(In millions except otherwise noted)	2017			2016
Retail revenue	$	2,813		$	2,816
Supply management revenue	84			64
Capacity revenue	42			29
Customer mark-to-market	—			(2		)
Contract amortization	(1		)	(1		)
Operating revenue^(a)	2,938			2,906
Cost of sales ^(b)	(2,211		)	(2,148		)
Mark-to-market for economic hedging activities	20			510
Contract amortization	—			(3		)
Gross Margin	$	747		$	1,265
Less: Mark-to-market for economic hedging activities, net	20			508
Less: Contract and emission credit amortization, net	(1		)	(4		)
Economic Gross Margin	$	728		$	761

Business Metrics
Mass electricity sales volume - GWh - Gulf Coast	16,218			15,386
Mass electricity sales volume - GWh - All other regions	2,998			3,278
C&I electricity sales volume — GWh - All regions	10,141			9,211
Natural gas sales volumes (MDth)	1,700			1,251
Average Retail Mass customer count (in thousands)	2,844			2,763
Ending Retail Mass customer count (in thousands)	2,887			2,771


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


(b)	Includes intercompany purchases of $465 million and $315 million in 2017 and 2016.

Retail gross margin decreased $518 million and economic gross margin decreased $33 million for the six months ended June 30, 2017, compared to the same period in 2016, due to:



	(In millions)
Lower gross margin due to lower revenue of $73 million or approximately $3 per MWh, driven by lower rates to customers, partially offset by lower supply costs of $21 million or approximately $1 per MWh driven primarily by a decrease in power prices at the time of procurement	$	(52	)
Lower gross margin of $18 million due to a reduction in load of 481,000 MWhs and $9 million in lower margin due to the unfavorable impacts of selling back excess supply due to milder weather conditions in 2017 compared to 2016	(27		)
Higher gross margin due to higher volumes driven by higher average customer usage and mix	46
Decrease in economic gross margin	$	(33	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(488		)
Increase in contract and emission credit amortization	3
Decrease in gross margin	$	(518	)

Renewables gross margin and economic gross margin

Renewables gross margin increased $25 million and economic gross margin increased $21 million for the six months ended June 30, 2017, compared to the same period in 2016, primarily driven by higher volume and pricing at the Ivanpah solar plant.

NRG Yield gross margin and economic gross margin

NRG Yield gross margin decreased by $9 million and economic gross margin decreased by $15 million during the six months ended June 30, 2017, compared to the same period in 2016, primarily driven by a decrease in volume generated at wind and solar projects due to weather conditions and lower generation at El Segundo and Walnut Creek as a result of forced outages in 2017.

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 $13 million during the six months ended June 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:



	Six months ended June 30, 2017
	Generation
	Gulf Coast			East/West^(a)			Retail			Renewables		Eliminations^(b)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(8	)	$	(37	)	$	(1	)	$	—	$	89		$	43
Net unrealized gains on open positions related to economic hedges	49			41			1			3		22			116
Total mark-to-market gains in operating revenues	$	41		$	4		$	—		$	3	$	111		$	159
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(7	)	$	2		$	76		$	—	$	(89	)	$	(18	)
Reversal of acquired loss positions related to economic hedges	—			—			1			—		—			1
Net unrealized losses on open positions related to economic hedges	(17		)	(5		)	(57		)	—		(22		)	(101		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(24	)	$	(3	)	$	20		$	—	$	(111	)	$	(118	)


(a)	Includes International and BETM.


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



	Six months ended June 30, 2016
	Generation
	Gulf Coast			East/West^(a)			Retail			Renewables			Eliminations^(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	$	(268	)	$	(67	)	$	(1	)	$	—		$	77		$	(259	)
Net unrealized (losses)/gains on open positions related to economic hedges	(181		)	1			(1		)	(1		)	19			(163		)
Total mark-to-market (losses)/gains in operating revenues	$	(449	)	$	(66	)	$	(2	)	$	(1	)	$	96		$	(422	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	19		$	8		$	264		$	—		$	(77	)	$	214
Reversal of acquired (gain)/loss positions related to economic hedges	—			(5		)	1			—			—			(4		)
Net unrealized gains/(losses) on open positions related to economic hedges	16			(2		)	245			—			(19		)	240
Total mark-to-market gains/(losses) in operating costs and expenses	$	35		$	1		$	510		$	—		$	(96	)	$	450


(a)	Includes International and BETM.


(b)	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 six months ended June 30, 2017, the $159 million gain in operating revenues from economic hedge positions was driven primarily by the increase in value of open positions as a result of decreases in PJM power prices, New York capacity prices, and natural gas prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $118 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 and natural gas prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the six months ended June 30, 2016, the $422 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, as well as a decrease in value of open positions as a result of increases in natural gas and ERCOT electricity prices. The $450 million gain in operating costs and expenses from economic hedge positions was driven primarily by the increase in value of open positions as a result of increases in natural gas and ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the six months ended June 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.



	Six months ended June 30,
(In millions)	2017			2016
Trading gains/(losses)
Realized	$	28		$	47
Unrealized	(2		)	32
Total trading gains	$	26		$	79

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)
Six months ended June 30, 2017	$	250	$	207	$	114	$	63	$	97	$	2	$	(21	)	$	712
Six months ended June 30, 2016	281		278		120		74		93		10		$	(14	)	842


(a)	Includes International, BETM and generation eliminations of $2 million in 2017 and $3 million in 2016.

Operations and maintenance expense decreased by $130 million for the six months ended June 30, 2017, compared to the same period in 2016, due to the following:



	(In millions)
Decrease in operation and maintenance expenses due primarily to major maintenance activities and environmental control work at Midwest Generation in 2016	$	(51	)
Decrease in Gulf Coast operation and maintenance expense due primarily to lower expenses at Big Cajun II in 2017	(31		)
Decrease in operations and maintenance expense primarily related to the deactivation of the Huntley and Dunkirk facilities in 2016	(15		)
Decrease in Renewables operation and maintenance expense primarily due to unplanned outages at Ivanpah in 2016 as well as cost reductions in 2017	(9		)
Decrease in Retail operation and maintenance expense due primarily to a reduction in employee expenses	(6		)
Decrease in operations and maintenance expense primarily related to the timing of outage work at Arthur Kill in 2016	(6		)
Other	(12		)
	$	(130	)

Selling, General and Administrative

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



	Generation		Retail		Renewables		NRG Yield		Corporate		Total
	(In millions)
Six months ended June 30, 2017	$	104	$	226	$	28	$	10	$	114	$	482
Six months ended June 30, 2016	136		226		31		6		121		520

Selling, general and administrative expenses decreased by $38 million for the six months ended June 30, 2017, compared to the same period in 2016, The decrease was primarily related to costs of $17 million incurred in 2016 related to severance and employee costs, partially offset by $20 million related to advisors engaged to assist the Company in its current strategic review in the current period. The remaining decreases in selling, general and administrative expenses year over year is due to the Company's continued focus on cost management.

Loss on Sale of Assets

During the six months ended June 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, as described in Note 3, Discontinued Operations and Dispositions, of this Form 10-Q, which resulted in a loss on sale of $83 million which included $56 million for the accrual of NRG's remaining obligation to the CPUC.

Impairment Losses on Investments

For the six months ended June 30, 2016, the Company recorded other-than-temporary impairment losses of $139 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 $69 million was recorded for the six months ended June 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 $8 million for the six months ended June 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 $101 million, partially offset by Senior Notes issued in 2016 of $70 million	$	(31	)
Decrease due to the redemption of bonds related to Peaker Finance Company, due 2019 during 2016	(7		)
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016	12
Increase in derivative interest expense from changes in fair value of interest rate swaps	10
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	5
Other	3
	$	(8	)

Income Tax (Benefit)/Expense

For the six months ended June 30, 2017, NRG recorded income tax benefit of $1 million on a pre-tax loss of $71 million. For the same period in 2016, NRG recorded income tax expense of $47 million on a pre-tax loss of $173 million. The effective tax rate was 1.4% and (27.2)% for the six months ended June 30, 2017 and 2016, respectively.

For the six months ended June 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense resulting from the change in the valuation allowance, amortization of indefinite lived assets, inclusion of consolidated partnerships and the impact of state income taxes.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the six months ended June 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, partially offset by NRG Yield, Inc.'s share of net income.

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

For the six months ended June 30, 2017 and 2016, NRG recorded losses from discontinued operations, net of income tax (benefit)/expense of $775 million and $9 million, respectively. Discontinued operations were comprised of the results of GenOn and the recording of certain liabilities in connection with the Restructuring Support Agreement, as further disclosed in Item 1 - Note 3, Discontinued Operations and Dispositions, of this Form 10-Q.

Liquidity and Capital Resources

Liquidity Position

As of June 30, 2017 and December 31, 2016, NRG's liquidity, excluding collateral received, was approximately $2.7 billion and $2.4 billion, respectively, comprised of the following:



(In millions)	June 30, 2017		December 31, 2016
Cash and cash equivalents:
NRG excluding NRG Yield	$	571	$	621
NRG Yield and subsidiaries	181		317
Restricted cash - operating	141		56
Restricted cash - reserves^(a)	328		390
Total	1,221		1,384
Total credit facility availability	1,497		989
Total liquidity, excluding collateral received	$	2,718	$	2,373

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

For the six months ended June 30, 2017, total liquidity, excluding collateral funds deposited by counterparties, increased by $345 million. Changes in cash and cash equivalents balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 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. 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.

On July 12, 2017, NRG announced its Transformation Plan, which is described further in Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Summary.

Credit Ratings

The following table summarizes the Company's credit ratings as of June 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
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

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 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

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.

Sale of Assets to NRG Yield, Inc.

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.

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 $41.5 million, excluding working capital adjustments. 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-scales solar acquisitions are subject to negotiation and approval by NRG Yield, Inc.'s independent directors.

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 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 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, and 10% of

its other assets, with these counterparties for the first 60 months and then declining thereafter. 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 June 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 June 30, 2017:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2017		2018		2019		2020		2021
In MW	1,562		1,033		—		—		—
As a percentage of total net coal and nuclear capacity ^(b)	29	%	19	%	—	%	—	%	—	%


(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 EME (Midwest Generation) 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.

Restructuring Support Agreement

As described in Note 3, Discontinued Operations and Dispositions, 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. GenOn’s liability for the pension liability as of June 30, 2017 was approximately $119 million.

Revolving Credit Facility

On June 12, 2017, NRG repaid $125 million on the Revolving Credit Facility. As of June 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 June 30, 2017, commercial operations had total cash collateral outstanding of $277 million, and $606 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of June 30, 2017, total collateral held from counterparties was $16 million in cash and $19 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 six months ended June 30, 2017, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2017.



	Maintenance		Environmental		Growth Investments			Total
	(In millions)
Generation
Gulf Coast	$	53	$	1	$	3		$	57
East/West	16		24		181			221
Retail	14		—		13			27
Renewables	2		—		213			215
NRG Yield	11		—		2			13
Corporate	6		—		3			9
Total cash capital expenditures for the six months ended June 30, 2017	102		25		415			542
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(593		)	(593		)
Other investments ^(a)	—		—		66			66
Total capital expenditures and investments, net of financings	102		25		(112		)	15

Estimated capital expenditures for the remainder of 2017	119		10		273			402
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(76		)	(76		)
NRG estimated capital expenditures for the remainder of 2017, net of financings	$	119	$	10	$	197		$	326


(a)	Other investments include restricted cash activity.


•	Environmental capital expenditures — For the six months ended June 30, 2017, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy CPS.


•	Growth Investments capital expenditures — For the six months ended June 30, 2017, the Company's growth investment capital expenditures included $184 million for repowering projects, $156 million for solar projects, $57 million for wind projects and $16 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 $32 million, which includes $17 million for Midwest Generation. The reduction from last quarter is driven primarily by the removal of the anticipated costs of complying with the ELG Rule, which costs the Company removed because the EPA is reconsidering the rule.

Dividends

The following table lists the dividends paid during the six months ended June 30, 2017:



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

On July 20, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2017, to stockholders of record as of August 1, 2017 representing $0.12 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. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

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
Total Fuel Repowerings	789

(a) Projects are subject to applicable regulatory approvals and permits.

(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 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 six month periods:



	Six months ended June 30,
	2017			2016			Change
	(In millions)
Net cash used by operating activities	$	74		$	811		$	(737	)
Net cash used by investing activities	(545		)	(470		)	(75		)
Net cash used by financing activities	18			(530		)	548

Net Cash Used By Operating Activities

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



	(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	$	(512	)
Decrease in operating income adjusted for non-cash items	(180		)
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	(78		)
Other	2
Cash provided by discontinued operations	31
	$	(737	)

Net Cash Used By Investing Activities

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



	(In millions)
Decrease in maintenance and environmental capital expenditures, offset by an increase in growth capital expenditures	$	(100	)
Increase in investments in unconsolidated affiliates	(30		)
Proceeds from sale of equipment	18
Net increase in nuclear decommissioning trust fund activity	11
Increase in insurance proceeds received in 2017 related to the Cottonwood generations station outage in 2016	10
Other	9
Cash provided by discontinued operations	7
	$	(75	)

Net Cash Provided By Financing Activities

Changes to net cash provided financing activities were driven by:



	(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	$	698
Increase due to purchase of preferred stock in 2016	226
Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016	38
Increase in cash contributions, net of distributions from non-controlling interest in 2017	35
Payment for affiliate receivable	(125		)
Decrease in financing element related to acquired derivatives	(3		)
Cash used by discontinued operations	(321		)
	$	548

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

For the six months ended June 30, 2017, the Company had a total domestic pre-tax book loss of $84 million and foreign pre-tax book income of $13 million. As of December 31, 2016, the Company 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.

In addition to these amounts, the Company has $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 million in 2017.

The Company has recorded a non-current tax liability of $39 million until final resolution with the related taxing authority. The $39 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 June 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 $620 million as of June 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 15, 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 six months ended June 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 June 30, 2017, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2017.



Derivative Activity (Losses)/Gains	(In millions)
Fair Value of Contracts as of December 31, 2016	$	(128	)
Contracts realized or otherwise settled during the period	26
Changes in fair value	(32		)
Fair Value of Contracts as of June 30, 2017	$	(134	)



	Fair Value of Contracts as of June 30, 2017
	Maturity
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)
Level 1	$	(54	)	$	(45	)	$	(7	)	$	—		$	(106	)
Level 2	(7		)	(2		)	(5		)	(3		)	(17		)
Level 3	(6		)	2			(1		)	(6		)	(11		)
Total	$	(67	)	$	(45	)	$	(13	)	$	(9	)	$	(134	)

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 June 30, 2017, NRG's net derivative liability was $134 million, a decrease to total fair value of $6 million as compared to December 31, 2016. This decrease was driven by losses in fair value, largely offset by the roll-off of trades that settled during the 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 $134 million in the net value of derivatives as of June 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 $159 million in the net value of derivatives as of June 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 natural gas prices continue to decrease, this could have a negative impact on the fair value of the reporting units that have goodwill balances and recovery of long-lived assets. Additionally, continued decreases in natural gas prices could result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. Accordingly, if these decreases continue, it is possible that the Company's goodwill or long-lived assets will be impaired.

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 six months ending June 30, 2017 and 2016:



(In millions)	2017		2016
VaR as of June 30,	$	49	$	63
Three months ended June 30,
Average	$	59	$	62
Maximum	66		68
Minimum	49		55
Six months ended June 30,
Average	$	56	$	58
Maximum	66		68
Minimum	41		44

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 June 30, 2017, for the entire term of these instruments entered into for both asset management and trading was $27 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 June 30, 2017, the Company would have owed the counterparties $48 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 June 30, 2017, a 1% change in variable interest rates would result in a $13.7 million change in interest expense on a rolling twelve month basis.

As of June 30, 2017, the fair value and related carrying value of the Company's debt was $17.2 billion and $17.0 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 $968 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 $261 million as of June 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 $129 million as of June 30, 2017. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 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 second quarter of 2017 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through June 30, 2017, see Note 15, 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. Except as presented below, there have been no material changes in the Company's risk factors since those reported in its 2016 Form 10‑K.

The GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code, and NRG is subject to the risks and uncertainties associated with bankruptcy proceedings.

On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, and REMA, did not file for relief under Chapter 11.

NRG is subject to a number of risks and uncertainties associated with the Chapter 11 Cases, which may lead to potential adverse effects on NRG’s business, results of operations, or financial condition. NRG cannot assure you of the outcome of the Chapter 11 Cases. Potential risks to NRG associated with the Chapter 11 Cases include the following:


•	the ability of the GenOn Entities to obtain Bankruptcy Court approval with respect to motions in the Chapter 11 proceedings and the outcomes of Bankruptcy Court rulings of the proceedings and appeals of such rulings in general;


•	the length of time the GenOn Entities will operate under the Chapter 11 proceedings and their ability to successfully emerge, including with respect to obtaining any necessary regulatory approvals;


•	the ability of the GenOn Entities to complete a plan of reorganization and NRG’s role in such plan of reorganization;


•	risks associated with third party motions, proceedings and litigation in the Chapter 11 proceedings, which may interfere with the GenOn Entities’ plan of reorganization;


•	NRG’s and the GenOn Entities’ ability to manage contracts that are critical to NRG’s operations, and to obtain and maintain appropriate credit and other terms with customers, suppliers and service providers;


•	NRG’s ability to attract, retain and motivate key employees;


•	NRG’s ability to fund and execute its business plan;


•	the disposition or resolution of all pre-petition claims against NRG and the GenOn Entities; and


•	NRG’s ability to maintain existing customers and vendor relationships and expand sales to new customers.

The Bankruptcy Court may not approve the Settlement Agreement, or even if the Settlement Agreement is approved, it may not be consummated if certain conditions are not met. If the Settlement Agreement is not approved and consummated, NRG may not be entitled to receive certain benefits contemplated by the Restructuring Support Agreement.

Under the Restructuring Support Agreement to which GenOn, 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 Settlement Agreement, subject to conditions.

There can be no assurance that the Bankruptcy Court will approve the Settlement Agreement, and even if it is approved, there can be no assurance that the conditions to the effectiveness of the Settlement Agreement will be satisfied. In addition, GenOn is entitled to terminate the Restructuring Support Agreement and consider alternative transactions in accordance with its fiduciary duties. If the Settlement Agreement is not approved, absent a separate agreement, NRG will not receive the benefits contemplated by the Restructuring Support Agreement.

The Chapter 11 Cases may disrupt NRG's business and may materially and adversely affect NRG's operations.

NRG has attempted to minimize the adverse effect of the GenOn Entities’ Chapter 11 Cases on NRG's relationships with its employees, suppliers, customers and other parties. Nonetheless, NRG's relationships with its employees, suppliers, customers and other parties may be adversely impacted by negative publicity or otherwise and NRG's operations could be materially and adversely affected. In addition, the Chapter 11 Cases could negatively affect NRG's ability to attract new employees and retain existing high performing employees or executives, which could materially and adversely affect NRG's operations.

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As a result of the Chapter 11 Cases, NRG's historical financial information will not be indicative of NRG's future financial performance.

NRG's corporate structure will be significantly altered under any plan of reorganization. As of June 14, 2017, GenOn and its consolidated subsidiaries were deconsolidated from NRG's financial statements. Consequently, NRG's results of operations following the deconsolidation will not be comparable to the financial condition and results of operations reflected in NRG's historical financial statements for periods prior to the deconsolidation.

NRG adopted and initiated the Transformation Plan. If the Transformation Plan does not achieve its expected benefits, there could be negative impacts to NRG’s business, results of operations and financial condition.

On July 12, 2017, NRG announced that it had adopted and initiated the 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 following components: (i) operations and cost excellence; (ii) portfolio optimization; and (iii) capital structure and allocation enhancements.

NRG cannot assure you that such components will result in the anticipated benefits to NRG’s business, results of operations and financial condition in a timely manner if at all. Further, NRG could experience unexpected delays, business disruptions resulting from supporting these initiatives during and following completion of these activities, decreased productivity, adverse effects on employee morale and employee turnover as a result of such initiatives, any of which may impair NRG’s ability to achieve anticipated results or otherwise harm NRG’s business, results of operations and financial condition.

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

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

See Note 3, Discontinued Operations and Dispositions, 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.

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ITEM 6 — EXHIBITS



Number	Description	Method of Filing
10.1	Consent Agreement, dated as of May 22, 2017, by and among GenOn Energy, Inc., NRG Energy, Inc. and the holders of Notes signatory thereto.	Incorporated herein by reference to Exhibit 10.1 to GenOn Energy, Inc. and GenOn Americas Generation, LLC's Current Report on Form 8-K filed on May 23, 2017.
10.2	Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on June 14, 2017.
10.3	Backstop Commitment Letter, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries signatory thereto and the noteholders signatory thereto.	Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on June 14, 2017.
10.4	Backstop Fee Letter, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries signatory thereto and the noteholders signatory thereto.	Incorporated herein by reference to Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on June 14, 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	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: August 3, 2017	Chief Accounting Officer (Principal Accounting Officer)

104